Potential Impacts of the 

Federal Regional Haze and 

Best Available Retrofit Technology 

Rules on the Taconite Industry in 

Minnesota

Final Report for the 

Minnesota Pollution Control Agency 

September 30, 2003 

Barr Engineering Company 

Project No. 23/62-833

CFMS Contract No. A45712 
i

Table of Contents 

1 Project Introduction and Background ....................................................................................................1 

1.1 Minnesota Pollution Control Agency Request for Proposal........................................................1 

1.2 Working Group Coordination Meeting........................................................................................1 

1.3 Project Tasks and Draft Reports ..................................................................................................2 

2 Purpose and Format of Report ...............................................................................................................3 

3 Summary of Regional Haze Final Rule .................................................................................................5 

3.1 Background..................................................................................................................................5 

3.2 40 CFR Part 51 Subpart P – Protection of Visibility...................................................................8 

3.2.1 Coordination of 1980 Visibility Rules and 1999 Regional Haze Rules ........................8 

3.2.2 40 CFR 51.300 Purpose and Applicability ....................................................................9 

3.2.3 40 CFR 51.301 Definitions............................................................................................9 

3.2.4 40 CFR 51.308 Regional Haze Program Requirements ................................................9 

3.2.5 40 CFR 51.309 Requirements for the GCVTC............................................................17 

3.3 Status of Minnesota Implementation Plan for Visibility Protection..........................................17 

3.4 Implementation of the Regional Haze Program in Indian Country ...........................................17 

3.4.1 Background on Tribal Air Quality Programs...............................................................17 

3.4.2 Issues Related to the Regional Haze Program in Indian Country................................18 

4 Summary of BART Guidelines Proposed Rule ...................................................................................20

4.1 Background................................................................................................................................20 

4.2 Guidelines for BART Determinations Under the Regional Haze Rule .....................................20 

4.2.1 Overview......................................................................................................................20 

4.2.2 How to Identify BART-Eligible Sources.....................................................................21 

4.2.3 How to Identify Sources “Subject to BART”..............................................................24 

4.2.4 Engineering Analysis of BART Options .....................................................................24 

4.2.5 Cumulative Air Quality Analysis.................................................................................26 

4.2.6 Enforceable Limits / Compliance Date........................................................................27 

4.2.7 Emissions Trading Program Overview........................................................................27 

4.3 Summary of Recent Court Rulings............................................................................................28 

4.3.1 May 2002 D.C. Circuit Court of Appeals Decision.....................................................28 

4.3.2 September 2002 D.C. Circuit Court of Appeals Decision...........................................31 

4.3.3 August 2003 Proposed Consent Decree for BART Deadline......................................31 

5 Taconite Industry Overview and BART-Eligible Source Identification .............................................32 

5.1 Iron Ore Ranges .........................................................................................................................32 

5.2 Taconite Mining and Processing Facilities................................................................................32

5.3 Taconite Pellets..........................................................................................................................32 

5.4 Mining........................................................................................................................................33 

5.5 Pellet Plant Overview ................................................................................................................33 

5.5.1 Crushing.......................................................................................................................33 

5.5.2 Ore Grinding and Iron Separation................................................................................33 

5.5.3 Pelletizing ....................................................................................................................34 

5.5.4 Induration.....................................................................................................................34 

5.5.5 Material Handling ........................................................................................................36 

5.6 Boilers, Heaters, and Diesel Engines.........................................................................................37 
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5.7 Taconite Industry Emissions Data .............................................................................................37 

5.8 BART-Eligible Sources .............................................................................................................38 

5.8.1 Initial MPCA BART Survey Request..........................................................................38 

5.8.2 Categorization of BART-Eligible Units at the Minnesota Taconite Plants.................38 

5.8.3 Taconite Industry Model Sources ................................................................................39 

6 Identification of Available Control Technologies ...............................................................................44 

6.1 NOx Emission Control Options.................................................................................................44 

6.1.1 External Flue Gas Recirculation ..................................................................................44 

6.1.2 Low-NOx Burners .......................................................................................................45 

6.1.3 Induced Flue Gas Recirculation Burners .....................................................................45 

6.1.4 Selective Non-Catalytic Reduction..............................................................................45 

6.1.5 Selective Catalytic Reduction......................................................................................46 

6.1.6 Ported Kilns .................................................................................................................46 

6.1.7 Coal Addition to Pellets with Low Excess Air in the Induration Furnace...................46 

6.1.8 Non-Selective Catalytic Reduction..............................................................................47 

6.1.9 Low Temperature Oxidation........................................................................................47 

6.1.10 Site-specific Measures .................................................................................................48 

6.2 SO2 Emission Control Options ..................................................................................................49 

6.2.1 Wet Walled Electrostatic Precipitator..........................................................................49 

6.2.2 Wet Scrubbing / Flue-Gas Desulfurization..................................................................49 

6.2.3 Dry Scrubbing Lime/Limestone Injection ...................................................................50 

6.2.4 Spray Dryer Absorption...............................................................................................50 

6.3 PM Emission Control Options...................................................................................................51 

6.3.1 Best Management Practices .........................................................................................51 

6.3.2 Wet Suppression ..........................................................................................................51 

6.3.3 Enclosure......................................................................................................................51 

6.3.4 Cyclone Separator........................................................................................................51 

6.3.5 Electrostatic Precipitator..............................................................................................52 

6.3.6 Wet Walled Electrostatic Precipitator..........................................................................52 

6.3.7 Fabric Filter..................................................................................................................52 

6.3.8 Particulate Scrubbers ...................................................................................................53 

7 Application of BART Screening to Model Taconite Sources .............................................................54 

7.1 General Control Technology Review Issues..............................................................................55 

7.1.1 Emission Controls vs. Impact on Visibility .................................................................55 

7.1.2 Site-specific Factors that Affect Control Costs ...........................................................55 

7.2 Model Source Parameters ..........................................................................................................57 

7.3 Model Induration Furnace NOx Control Technology Review ..................................................59 

7.3.1 BART Step 1: Identify All Available Retrofit Control Technologies .........................59 

7.3.2 BART Step 2: Eliminate Technically Infeasible Options............................................59 

7.3.3 BART Step 3: Rank Remaining Control Technologies...............................................63 

7.3.4 BART Step 4: Evaluate Impacts and Document the Results.......................................64 

7.4 Model Induration Furnace SO2 Control Technology Review....................................................66 

7.4.1 BART Step 1: Identify All Available Retrofit Control Technologies .........................67 

7.4.2 BART Step 2: Eliminate Technically Infeasible Options............................................67 

7.4.3 BART Step 3: Rank Remaining Control Technologies...............................................67 

7.4.4 BART Step 4: Evaluate Impacts and Document the Results.......................................67 
iii

7.5 Model Induration Furnace PM Control Technology Review ....................................................69 

7.5.1 BART Step 1: Identify All Available Retrofit Control Technologies .........................69 

7.5.2 BART Step 2: Eliminate Technically Infeasible Options............................................69 

7.5.3 BART Step 3: Rank Remaining Control Technologies...............................................70 

7.5.4 BART Step 4: Evaluate Impacts and Document the Results.......................................70 

7.6 Model Pellet Cooler PM Control Technology Review..............................................................71 

7.6.1 BART Step 1: Identify All Available Retrofit Control Technologies .........................72 

7.6.2 BART Step 2: Eliminate Technically Infeasible Options............................................72 

7.6.3 BART Step 3: Rank Remaining Control Technologies...............................................72 

7.6.4 BART Step 4: Evaluate Impacts and Document the Results.......................................73 

7.7 Model Material Ore Material Handling PM Control Technology Review................................74 

7.7.1 BART Step 1: Identify All Available Retrofit Control Technologies .........................74 

7.7.2 BART Step 2: Eliminate Technically Infeasible Options............................................75 

7.7.3 BART Step 3: Rank Remaining Control Technologies...............................................76 

7.7.4 BART Step 4: Evaluate Impacts and Document the Results.......................................76 

7.8 Fugitive Dust Emissions ............................................................................................................77 

8 Affordability ........................................................................................................................................79 

8.1 BART Alternative Cost Inventory.............................................................................................79 

8.2 Financial Information Inventory................................................................................................80 

8.3 Affordability Evaluation Summary............................................................................................80 

9 Summary of Existing and Proposed Air Pollution Regulatory Requirements.....................................82 

9.1 Federal Standards of Performance for Metallic Mineral Processing Plants ..............................92 

9.1.1 Applicability ................................................................................................................92 

9.1.2 Particulate Matter Standards........................................................................................93 

9.1.3 Compliance Testing and Monitoring ...........................................................................93 

9.2 Federal Standards of Performance for Coal Preparation Plants, NSPS Subpart Y....................94 

9.3 National Emission Standards for Hazardous Air Pollutants for Taconite Iron Ore 

Processing ..............................................................................................................................................94 

9.3.1 Affected Sources..........................................................................................................94 

9.3.2 Emission Limits and Work Practice Standards............................................................94 

9.3.3 Operation and Maintenance .........................................................................................96 

9.3.4 Initial Compliance Testing...........................................................................................96 

9.3.5 Continuous Compliance...............................................................................................97 

9.3.6 Compliance Deadlines .................................................................................................97 

9.4 Minnesota Rules, Chapter 7011, Standards for Stationary Sources ..........................................97 

9.4.1 Minn. R. 7011.0150 – Preventing Particulate Matter from Becoming Airborne ........98 

9.4.2 Standards of Performance for Fossil Fuel-Burning Direct Heating Equipment..........98 

9.4.3 Standards of Performance for Pre-1969 Industrial Process Equipment.......................99 

9.4.4 Standards of Performance for Post-1969 Industrial Process Equipment.....................99 

9.4.5 Standards of Performance for New Coal Preparation Plants.......................................99 

9.4.6 Standards of Performance for New Metallic Mineral Processing Plants.....................99 

9.5 Michigan Air Pollution Control Rules.......................................................................................99 

9.5.1 Part 3 – Particulate Matter Emission Limitations and Prohibitions...........................100 

9.5.2 Part 4 – Sulfur-Bearing Compounds Emission Limitations and Prohibitions ...........101 

9.5.3 Part 7 – New Sources of VOC Emissions – Limitations and Prohibitions................101 

9.5.4 Part 8 – Emission Limitations and Prohibitions - Oxides of Nitrogen ......................102 
iv

9.6 Summary of Canadian Provincial Air Pollution Control Regulations.....................................102 

9.6.1 Newfoundland Air Pollution Control Regulations ....................................................102 

9.6.2 Ontario Air Pollution Control Regulations................................................................103 

9.6.3 Quebec Air Pollution Control Regulations................................................................104 

9.7 Summary of BACT Determinations ........................................................................................108 

10 Visibility Impacts Screening Evaluation of the Taconite Industry....................................................109 

10.1 Modeling Protocol ...................................................................................................................109 

10.1.1 Modeling Program .....................................................................................................109

10.1.2 Sources.......................................................................................................................110 

10.1.3 Pollutants and Emission Rates...................................................................................112 

10.1.4 Receptors....................................................................................................................112 

10.1.5 Model Control Selections ..........................................................................................112 

10.2 Modeling Results .....................................................................................................................113 

11 Conclusions........................................................................................................................................116 
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List of Tables 

Table 3-1 1999 Regional Haze Amendments Made to the 1980 Visibility Rules in 40 CFR Part 51...... 8 

Table 3-2 Anticipated Timeline for Compliance with BART Requirements......................................... 11 

Table 3-3 Timeline for First Regional Haze SIP Submittal by Area Designation.................................. 12 

Table 4-1 BART Review vs. BACT Review.......................................................................................... 25 

Table 5-1 Emissions of Visibility-Impairing Pollutants from the Eight U.S. Taconite Facilities by 

State..................................................................................................................................... 38 

Table 5-2 Emission Unit Categories at Taconite Ore Processing Facilities ........................................... 39 

Table 5-3 BART Eligible Source Classification for Taconite Industry Sources.................................... 41 

Table 5-4 2001 PM10 Emissions (tpy) Breakdown for Group 2 and 3 Source Categories.................... 42 

Table 5-5 2001 SO2 and NOx Emissions (tpy) Breakdown by Type of Induration Furnace ................. 43 

Table 7-1 Taconite Model Source Characteristics for BART Screening Evaluation ............................. 58 

Table 7-2 Summary of Technical Feasibility for Induration NOx Emissions........................................ 60 

Table 7-3 Control Technology Rankings for Induration NOx Control .................................................. 64 

Table 7-4 Control Technology Rankings for Induration SO2 Control.................................................... 67 

Table 7-5 Applicable PM and Opacity Emission Limitations at Taconite Induration Furnaces............ 69 

Table 7-6 Control Technology Rankings for Induration PM Control .................................................... 70 

Table 7-7 Control Technology Rankings for Pellet Cooler PM Control................................................ 73 

Table 7-8 Applicable PM and Opacity Emission Limitations at Ore Material Handling Sources......... 74 

Table 7-9 Summary of Technical Feasibility for Ore Material Handling PM Emissions ...................... 75 

Table 7-10 Control Technology Rankings for Ore Material Handling PM Control............................... 76 

Table 7-11 Available PM Control Technologies for Fugitive Sources .................................................. 78 

Table 9-1 Air Quality Standards for Taconite Fugitive Particulate Sources .......................................... 83 

Table 9-2 Air Quality Standards for Taconite Point Particulate Sources ............................................... 84 

Table 9-3 Air Quality Standards for Taconite Induration Sources......................................................... 88 

Table 9-4 PM Emission Limits under the Proposed NESHAPs............................................................. 95 

Table 9-5 Continuous Parameter Monitoring and Associated Operating Limits ................................... 95 

Table 9-6 Minnesota Standards for Stationary Sources Relevant to Standards of Performance at 

Taconite Plants .................................................................................................................... 98 

Table 9-7 MDEQ APC Rules Relevant to Standards of Performance at Taconite Plants.................... 100 

Table 9-8 Maximum Allowable PM Emission Rates for Grate Kilns and Traveling Grates ............... 100 

Table 9-9 Maximum Concentration of a Contaminant at a Point of Impingement .............................. 103 

Table 9-10 Maximum Concentration of a Contaminant at a Point of Impingement ............................ 104 

Table 9-11 PM Emission Limits for Fossil Fuel Burning Equipment.................................................. 106 

Table 9-12 NOx Emission Limits for New Fuel Burning Equipment.................................................. 107 

Table 9-13 PM Emission Limits for Induration Processes at an Iron Ore Pelletizing Plant ................ 108 

Table 10-1 Sources and Stack Parameter Data in CALPUFF Input File.............................................. 110 

Table 10-2 Pre-BART and Post-BART Taconite Industry Emission Rates in CALPUFF Input File.. 112 

Table 10-3 Comparison of Modeling Results Between Pre-BART and Post-BART Taconite 

Industry Emissions ............................................................................................................ 114 

Table 11-1 Summary of Technically Feasible Control Technologies .................................................. 118 
vi

List of Figures 

Figure 3-1 Map of 156 National Park and Wilderness Areas Protected by EPA's Regional Haze 

Rule ....................................................................................................................................... 7 

Figure 3-2 Locations of Indian Reservations, Federal Class I Areas, and Taconite Plants.................. 19 

Figure 5-1 General Diagram of a Straight Grate Induration Furnace................................................... 35 

Figure 5-2 General Diagram of a Grate/Kiln Induration Furnace ........................................................ 35 

Figure 7-1 Equilibrium NOx Concentrations at Various Temperatures for a Typical Induration 

Furnace Waste Gas.............................................................................................................. 61 

Figure 7-2 Impact of Temperature on NOx Formation......................................................................... 62 

Figure 10-1 Location of Modeled Plant and Class I Area Receptors. .................................................. 111 

Figure 10-2 Daily Change in Light Extinction from Pre-BART and Post-BART Taconite Industry 

Emissions .......................................................................................................................... 115 

List of Attachments 

Attachment A December 9, 2002, State Register 

Attachment B MPCA Request for Proposal 

Attachment C March 18, 2003, Working Group Meeting Minutes and Attachments 

Attachment D July 1, 1999, Federal Register Notice - Regional Haze Regulations; Final Rule 

Attachment E Review of 40 CFR Sections 51.302 through 51.307 

Attachment F July 20, 2001, Federal Register Notice - Proposed Guidelines for Best Available 

Retrofit Technology (BART) Determinations Under the Regional Haze 

Regulations; Proposed Rule 

Attachment G May 24, 2002, District of Columbia Court of Appeals Decision (no. 99-1348), 

American Corn Growers Association vs. EPA 

Attachment H September 8, 2003, Federal Register Notice – Proposed Consent Decree For 

BART Rule Promulgation Deadlines 

Attachment I Model BART Cost Analysis – Induration Furnace NOx Emissions 

Attachment J Model BART Cost Analysis – Induration Furnace SO2 Emissions 

Attachment K Model BART Cost Analysis – Induration Furnace PM Emissions 

Attachment L Model BART Cost Analysis – Pellet Cooler PM Emissions 

Attachment M Model BART Cost Analysis – Iron Ore Material Handling PM Emissions 

Attachment N Control Technology Literature Search References 

Attachment O Applicable Minnesota Air Regulations 

Attachment P Applicable Michigan Air Regulations 

Attachment Q Applicable Canadian Provincial Air Regulations 

Attachment R RBLC Taconite Industry Query Results 

Attachment S August 25, 2003, Barr Memorandum “CALPUFF Screening Protocol for Taconite 

Industry BART Project” sans Attachments 

Attachment T CALMET Input File (One of Four Files) 

Attachment U CALPUFF Input File (One of Six Files) 

Attachment V CALPOST Input File (One of Six Files) 
1

1 Project Introduction and Background 

1.1 Minnesota Pollution Control Agency Request for Proposal 

On December 9, 2002, the Minnesota Pollution Control Agency (MPCA) published in the State 

Register the availability of a request for proposal to survey and report on the potential impacts of 

the federal Regional Haze rule on the taconite industry in Minnesota. See Attachment A for a 

copy of the State Register notice and the request for proposal. This rule requires certain sources 

to conduct an initial analysis that may lead to a more detailed assessment and installation of 

emissions controls that conform to Best Available Retrofit Technology (BART) requirements in 

40 CFR 51.308(e). The taconite industry has been identified by the MPCA as one of the 

industries for which a BART analysis is required. The MPCA requested that this project provide 

a general analysis for the industry as a whole that can be used by both the MPCA and the 

taconite industry as a basis for planning purposes and for any facility-specific detailed 

assessments that will follow. The analysis should be structured to help ensure that each facility 

conducts its engineering assessments the same way, the consistency of which will assist the 

MPCA in reviewing the assessments. The MPCA also requested that the project provide enough 

baseline information to initiate its own preliminary assessments, which are likely to be necessary 

to develop state implementation plan (SIP) submittals. The MPCA chose Barr Engineering 

Company (Barr) on January 27, 20031

 to complete the project. 

Barr Engineering Company’s (Barr’s) work plan to address MPCA’s request includes the 

following tasks: 

• Task 1: Hold working group coordination meeting. 

• Task 2: Conduct taconite industry regional haze regulatory study. 

• Task 3: Conduct general taconite industry BART screening analysis. 

• Task 4: Evaluate BART affordability issues. 

• Optional Task 2: Perform CALPUFF visibility impacts screening analysis. 

Attachment C of this report contains Barr’s work plan, located after the working group meeting 

minutes in the attachment. 

1.2 Working Group Coordination Meeting 

A necessary first step for this project is a coordination meeting with members of the working 

group. The working group includes MPCA and Barr personnel, representatives of the Minnesota 

taconite plants, representatives of Indian tribes, and other stakeholders. Task 1, a project kick-off 

meeting for the working group, was held at Barr’s Minneapolis office on March 18, 2003. The 

 

1

 January 27, 2003 phone conversation between Mr. Stuart Arkley of MPCA and Mr. George Pruchnofski of Barr. 
2

purpose of the meeting was to (1) provide contact information, (2) establish lines of 

communication, and (3) review the project work plan. 

Attachment C contains a copy of the meeting minutes in outline format and the meeting handouts 

that were sent via e-mail to the working group by Mr. Stuart Arkley on April 2, 2003. Included 

in this attachment is Barr’s project work plan. 

1.3 Project Tasks and Draft Reports 

Task 2 of the project is to complete a regulatory study report that summarizes the Regional Haze 

and BART regulations as they may apply to the taconite industry in Minnesota. Barr submitted 

the draft regulatory study report for review by the working group on April 18, 2003. Revisions to 

the report were completed on May 12, 2003, pursuant to comments from the working group. This 

report incorporates and supersedes the May 12, 2003 draft report. 

Task 3 of the project is to complete a BART screening evaluation of the taconite industry in 

order to provide information that will assist MPCA in developing baseline conditions for future 

BART evaluations. Barr submitted a draft report on July 11, 2003. Several comments were 

received on the draft report. Barr staff worked with each commenter to address concerns and has 

subsequently revised the draft report, as appropriate. This report incorporates and supersedes the 

July 11, 2003 draft report. 

Task 4 of the project is to address the aspect of affordability in a BART evaluation. This task 

was completed on September 23, 2003; the results are included in this report. 

Finally, Optional Task 2 of the project is to perform a dispersion modeling screening analysis of 

visibility impacts for the taconite industry before and after application of BART. This task was 

completed on September 23, 2003; the modeling protocol and results are included in this report. 
3

2 Purpose and Format of Report 

The objectives of this report are to: 

1) Detail the potential regulatory applicability of Federal Regional Haze and BART rules to 

the taconite industry (Sections 3 and 4), 

2) Describe the BART screening evaluation performed for the taconite industry (Sections 5 

through 8), 

3) Provide information to assist the MPCA in developing baseline conditions for future 

BART evaluations (Section 9), and 

4) Summarize the visibility impacts screening analysis (Section 10). 

Section 3 of this report provides a summary of the Regional Haze final rule as it applies to the 

taconite industry. This section serves to inform stakeholders of upcoming regulatory 

requirements under the Federal rule. As applicable, each provision of the rule is summarized, 

followed by a section discussing its relationship to the taconite industry. 

Section 4 summarizes the BART Guidelines proposed rule as it applies to the taconite industry 

and recent court opinions concerning the legality of certain BART provisions and timing for 

promulgation of a final rule. As with Section 3 for the Regional Haze rule, Section 4 serves to 

inform stakeholders of upcoming regulatory requirements under the proposed BART rule. 

Section 5 includes a summary description of the United States taconite iron ore industry, 

followed by a discussion of BART-eligible sources at Minnesota taconite facilities. 

Section 6 identifies available control technologies for the taconite industry and screens out those 

technologies that are technically infeasible for a new or existing unit. 

Section 7 steps through the BART screening evaluation for hypothetical model taconite sources. 

Section 8 of this report provides information to assist the MPCA in further developing baseline 

conditions for BART based on existing regulatory programs. It includes a summary of air 

pollution regulatory requirements that apply to the taconite industry and a summary of taconite 

emissions source types and control types used to meet the regulatory requirements. This section 

also provides a review summary of the MPCA’s existing emissions inventory of haze-generating 

pollutants for the taconite industry and BART-eligible sources. This section will help the MPCA 

to assess the effects of these programs in establishing BART for the industry and setting 

reasonable progress goals in developing the SIP. Also contained in this section is a summary of 

Michigan and Canadian air emissions control programs applicable to the taconite plants in these 

areas, as well as a summary of past best available control technology (BACT) determinations at 

taconite facilities. 

Section 9 provides the results of attempts to assess the affordability of a BART evaluation for the 

taconite industry. 

Section 10 summarizes the visibility impacts screening analysis performed using taconite 

industry pre-BART and hypothetical post-BART emissions. Although application of these 
4

modeling results is very limited, this analysis serves to provide generalized outcomes of visibility 

impacts at Boundary Waters Canoe Area Wilderness and Voyageurs National Park in Minnesota 

from the taconite industry. 

Section 11 sets forth conclusions that can be drawn from the report. 
5

3 Summary of Regional Haze Final Rule 

The information provided in this section is based on EPA’s July 1, 1999 “Regional Haze 

Regulations; Final Rule.”2

 A copy of the Federal Register notice is contained in Attachment D. 

Section 3.1 provides historical background on the development of this rule. Section 3.2 is a 

summary of the Regional Haze program requirements with a discussion of how each provision 

relates to BART at the taconite facilities. Section 3.3 summarizes the current status of the 

Minnesota implementation plan for visibility protection. Section 3.4 describes how the 

requirements of the Regional Haze rule relate to emissions released from Indian Country. 

3.1 Background 

Section 169a of the Clean Air Act (CAA) sets forth a national goal for visibility which is the 

“prevention of any future, and the remedying of any existing, impairment of visibility in 

mandatory Class I Federal areas (Class I areas) which impairment results from manmade air 

pollution.” All mandatory Class I Federal areas where visibility is an important value are listed in 

40 CFR 81, subpart D. Of the 156 Class I areas in the United States where visibility is an 

important value3

 (see Figure 3-1), two are in Minnesota: the Boundary Waters Canoe Area 

Wilderness (BWCAW) and Voyageurs National Park. 

Regional Haze is defined in 40 CFR Subpart P – Protection of Visibility, as: 

“...visibility impairment that is caused by the emission of air pollutants from numerous 

sources located over a wide geographic area. Such sources include, but are not limited to, 

major and minor stationary sources, mobile sources, and area sources.” 

The EPA promulgated regulations in 19804 to address visibility impairment that is “reasonably 

attributable” to one or a small group of sources, but EPA deferred action on Regional Haze 

regulations until monitoring, modeling, and scientific knowledge about the relationship between 

pollutants and the visibility effects improved. In 1993, the National Academy of Sciences (NAS) 

concluded that “current scientific knowledge is adequate and control technologies are available 

for taking regulatory action to improve and protect visibility.” On July 31, 1997, EPA published 

proposed amendments to the 1980 regulations to set forth a program to address Regional Haze 

visibility impairment. The Regional Haze final rule was published in the Federal Register on 

 

2

 64 FR 35713. 

3

 Only two of the 158 mandatory Class I areas currently do not have visibility air quality related values (AQRVs): 

Rainbow Lakes in northwest Wisconsin and Bradwell Bay in Florida (“New Source Review Workshop Manual 

(DRAFT),” U.S. EPA, Table E-1, October 1990). 

4

 45 FR 80084 (December 2, 1980) and 40 CFR 51 Subpart P – Protection of Visibility. 
6

July 1, 1999. The BART guidelines proposed rule was published in the Federal Register on 

July 20, 2001. 
7

Figure 3-1. Map of 156 National Park and Wilderness Areas Protected by EPA's Regional Ha
8

3.2 40 CFR Part 51 Subpart P – Protection of Visibility 

3.2.1 Coordination of 1980 Visibility Rules and 1999 Regional Haze Rules 

The 1980 visibility rules promulgated in 40 CFR Part 51 Subpart P were revised in 1999 to 

incorporate the 1999 Regional Haze rules. Table 3-1 below summarizes the amendments made to 

this regulatory subpart to coordinate the requirements of the Regional Haze rule with the1980 

visibility regulations. 

Table 3-1 

1999 Regional Haze Amendments Made to the 1980 Visibility Rules in 40 CFR Part 51 

Section Amendment 

51.300 Purpose and 

Applicability 

Amended to clarify that Subpart P includes provisions for Regional Haze as well 

as reasonably attributable visibility impairment. 

51.301 Definitions Added the following terms: reasonably attributable visibility impairment, Regional 

Haze, deciview, State, most impaired days, least impaired days, implementation 

plan, Indian tribe, BART-eligible source, and geographic enhancement. 

Revised the following terms: Federal Land Manager, major stationary source, 

natural conditions, and visibility impairment. 

51.302 Implementation 

Control Strategies 

Changed references to the administrative process requirements for public 

hearings and SIP submissions. 

Amended to clarify that the implementation control strategies apply to 

reasonably attributable visibility impairment. 

51.303 Exemptions No changes were made to this section in the 1999 amendments to the rule. 

51.304 Integral Vistas No changes were made to this section in the 1999 amendments to the rule. 

51.305 Monitoring Amended to clarify that the monitoring requirements apply to reasonably 

attributable visibility impairment. 

51.306 Long-term 

Strategy 

Amended to clarify that the long-term strategy requirements apply to reasonably 

attributable visibility impairment. 

Revised the periodic review and revision schedule 

51.307 New Source 

Review 

Amended to clarify that the new source review requirements apply to reasonably 

attributable visibility impairment. 

Revised the periodic review and revision schedule. 

51.308 Regional Haze 

Program Requirements 

New section to establish requirements for implementation plans, plan revisions, 

and periodic progress reviews to address Regional Haze. 

51.309 Requirements 

Related to the Grand 

Canyon Visibility 

Transport Commission 

New section to establish the requirements for the first Regional Haze 

implementation plan to address Regional Haze visibility impairment in the 16 

Class I areas covered by the Grand Canyon Visibility Transport Commission 

Report. 

Sections 3.2.2 through 3.2.5 of this report summarize rule Sections 40 CFR 51.300, 51.301, 

51.308, and 51.309. The requirements in 40 CFR Sections 51.302 through 51.307 relate 

primarily to the reasonably attributable visibility impairment rules originally promulgated in 
9

1980. A summary and discussion of how these provisions relate to BART at the taconite 

facilities is included in Attachment E. 

3.2.2 40 CFR 51.300 Purpose and Applicability 

A primary purpose of the rule is to require states to develop programs to assure reasonable 

progress toward meeting the national goal of preventing any future, and remedying any existing, 

impairment of visibility in Class I areas which impairment results from manmade air pollution. 

The rule establishes requirements addressing visibility impairment in its two principal forms: 

“reasonably attributable” impairment (i.e., impairment attributable to a single source/small group 

of sources) and Regional Haze (i.e., widespread haze from a multitude of sources which impairs 

visibility in every direction over a large area). 

The requirements for implementation plans to address reasonably attributable visibility 

impairment are applicable to each state with a Class I area (35 states, including Minnesota, and 

the Virgin Islands). The rule requirements for implementation plans to address Regional Haze 

visibility impairment are applicable to each state in which the emissions from any source may 

reasonably be anticipated to cause or contribute to visibility impairment (all states, including 

Minnesota). 

How does this provision relate to BART at taconite facilities? 

This provision identifies Minnesota as a state subject to the rule and establishes the requirement 

that the MPCA must develop an implementation plan to address both reasonably attributable 

visibility impairment and Regional Haze visibility impairment. As detailed in Section 3.2.4, the 

Regional Haze implementation plan will contain BART limitations for BART-eligible sources. 

3.2.3 40 CFR 51.301 Definitions 

This section establishes the definitions of terms for the rule. 

How does this provision relate to BART at taconite facilities? 

A “BART-eligible source” is defined as an “existing stationary facility.” An “existing stationary 

facility” is any facility that meets certain source category, timing, and emissions criteria. 

Taconite ore processing facilities are one of the 26 source categories listed in this definition. See 

Section 4.2 for additional details of BART applicability to taconite ore processing facilities. 

3.2.4 40 CFR 51.308 Regional Haze Program Requirements 

3.2.4.1 Purpose 

This new section in 40 CFR 51, subpart P, establishes implementation plans requirements to 

address Regional Haze. This section is divided into the following subsections: 

1. Schedule for implementation plans, 

2. Regional planning, 

3. Core requirements for the Regional Haze implementation plan, 
10

4. BART requirements for Regional Haze visibility impairment, 

5. Requirements for comprehensive periodic revisions of implementation plans for Regional 

Haze, 

6. Requirements for periodic reports describing progress towards the reasonable progress goals, 

7. Determination of the adequacy of existing implementation plan, and 

8. Requirements for State and FLM coordination. 

3.2.4.2 Schedule for Implementation Plans 

Each state must submit an implementation plan meeting the core requirements for the Regional 

Haze implementation plan and the BART requirement for Regional Haze visibility (described in 

Sections 3.2.4.4 and 3.2.4.5, respectively) by the following dates: 

• For any area designated as attainment or unclassifiable for the national ambient air 

quality standard (NAAQS) for fine particulate matter (PM2.5), the state must submit a 

Regional Haze implementation plan to EPA within 12 months after the date of 

designation. 

• For any area designated as nonattainment for the PM2.5 NAAQS, the state must submit a 

Regional Haze implementation plan to EPA at the same time that the state's plan for 

implementation of the PM2.5 NAAQS must be submitted, that is, within 3 years after the 

area is designated as nonattainment, but not later than December 31, 2008. 

This schedule is summarized in Table 3-3. 

How does this provision relate to BART at taconite facilities? 

This provision establishes the timeline for SIP submittal by the MPCA, which is dependent on 

the date of PM2.5 designation by EPA and the designation status in northern Minnesota. 

In a memo to the regional administrators5

, EPA requests a list of recommended PM2.5

designations from states and tribes by February 15, 2004. It is EPA’s policy to use the most 

recent three years of data available at the time of the designations; because EPA plans to 

promulgate final designations on December 15, 2004, it intends to consider the 2001 to 2003 

data in making those designations. The EPA plans to announce its intended designations in July 

2004 and will provide 120 days for states and tribes to comment. The EPA plans to publish final 

PM2.5 designations for all areas on December 15, 2004. The EPA intends to propose and finalize 

the PM2.5 implementation rule by September 2004, prior to issuing final designations, so that the 

implementation rule may be taken into consideration during the designation process. 

Initial PM2.5 ambient monitoring data have been collected at 22 sites in Minnesota6

 from April 

1999 to September 2000. Based on these initial monitoring results, none of the sites exceed the 

new PM2.5 standard, although two sites in St. Paul are close to the annual average standard. 

 

5

 EPA memo to the Regional Administrators: “Designations for the Fine Particle National Ambient Air Quality 

Standards,” April 1, 2003. 

6

 From MPCA’s 2001 legislative report, “Air Quality in Minnesota: Problems and Approaches,” Appendix B. 
11

While it is too early to determine trends with less than two years of PM2.5 sampling, based on the 

existing data, it appears that the first Regional Haze SIP will be due December 15, 2005. 

Table 3-2 provides an anticipated timeline for compliance with individual BART limitations 

based on the information provided above. 

Table 3-2 

Anticipated Timeline for Compliance with BART Requirements 

Date Item 

February 15, 2004 MPCA PM2.5 designation recommendations due to EPA 

April 15, 2004 Deadline for EPA to sign a notice of proposed rulemaking revising BART regulations 

and guidelines* 

July 15, 2004 EPA announces intended PM2.5 designations 

October 15, 2004 Comments due to EPA regarding recommended PM2.5 designations 

December 15, 2004 EPA publishes final PM2.5 designations 

April 15, 2005 Deadline for EPA to sign a notice of final rulemaking revising BART regulations and 

guidelines* 

December 15, 2005 MPCA’s Regional Haze SIP due for areas designated attainment for PM2.5

December 15, 2007 Following public notice and comment period, EPA approves MPCA’s Regional Haze 

SIP 

December 15, 2012 Compliance with BART required 

* See Section 4.3.3 of this report. EPA must also submit the notices of proposed and final rulemaking to the Office of 

Federal Register no later than five days following signature. 

3.2.4.3 Regional Planning 

If a state chooses to participate in a regional planning process, it may defer addressing the core 

requirements for Regional Haze and the requirements for BART. If a state opts to do this, it 

must: (1) submit an implementation plan demonstrating its commitment to regional planning by 

the earliest date by which an implementation plan would be due for any area of the state, and (2) 

submit an implementation plan revision addressing the Regional Haze and BART requirements 

by the latest date an area within the planning region would be required to submit an 

implementation plan, but not later than December 31, 2008. The timeline for such SIP submittals 

are presented in Table 3-3. 
12

Table 3-3 

Timeline for First Regional Haze SIP Submittal by Area Designation

Area Designation Due Date of First Regional Haze SIP 

Attainment or unclassifiable for PM2.5 1 yr after EPA publishes designation (~2004-2006) 

Nonattainment for PM2.5 Same time PM2.5 SIPs are due (3 yrs after EPA publishes 

designation (~2006-2008) 

Multistate regional planning for 

combined attainment and nonattainment 

Phase I: commitment to regional planning SIP – due 1 year after 

EPA publishes first designation for any area within the state 

Phase II: complete Regional Haze SIP - due same time PM2.5 SIPs 

are due; 3 years after EPA publishes designation (~2006-2008) 

How does this provision relate to BART at taconite facilities? 

This provision establishes the requirements and timeline the MPCA must follow if it chooses to 

defer addressing the core requirements for Regional Haze and BART if the state is participating 

in a regional planning process. 

The MPCA is currently participating in the Central Regional Air Planning Association 

(CenRAP) process to develop a Regional Haze SIP. CenRAP is an organization of states, tribes, 

federal agencies and other interested parties that identifies Regional Haze and visibility issues 

and develops strategies to address them. CenRAP is one of the five Regional Planning 

Organizations (RPOs) across the U.S. and includes the states and tribal areas of Minnesota, Iowa, 

Nebraska, Missouri, Kansas, Arkansas, Oklahoma, Louisiana, and Texas. CenRAPs goals are as 

follows: 

• Promote policies that ensure fair and equitable treatment of all participating members, 

• Provide coordination of science and technology to support air quality policy issues in the 

central region, 

• Recommend strategies on air quality issues for use by member states and tribes in 

developing implementation programs, regulations and laws, and 

• Conduct research and undertake other activities as necessary for information to support 

the development of sound state and tribal air pollution policies. 

3.2.4.4 Core requirements for the Regional Haze implementation plan 

The state must address Regional Haze in each Class I area located within the state and in each 

Class I area located outside the state which may be affected by emissions from within the state. 

To meet the core requirements for Regional Haze for these areas, the state must submit an 

implementation plan containing the following elements and supporting documentation for all 

required analyses: 

• Reasonable progress goals (expressed in deciviews) for each Class I area located within 

the state that for achieving natural visibility conditions. The goals must provide for an 
13

improvement in visibility for the most impaired days over the period of the 

implementation plan and ensure no degradation in visibility for the least impaired days 

over the same period. 

• Calculations of baseline and natural visibility conditions (expressed in deciviews) for 

each Class I area located within the state. 

• Long-term strategy for Regional Haze that addresses Regional Haze visibility impairment 

for each Class I area within the state and for each Class I area located outside the state 

which may be affected by emissions from the state. The long-term strategy must include 

enforceable emissions limitations, compliance schedules, and other measures as 

necessary to achieve the reasonable progress goals. 

• Monitoring strategy and other implementation plan requirements for measuring, 

characterizing, and reporting of Regional Haze visibility impairment that is representative 

of all Class I areas within the state. 

How does this provision relate to BART at taconite facilities? 

This provision requires the MPCA to submit a SIP containing the following core requirements 

for the Regional Haze SIP: 

1. Reasonable progress goals; 

2. Calculations of baseline and natural visibility conditions; 

3. Long-term strategy for Regional Haze; and 

4. Monitoring strategy and other implementation plan requirements. 

3.2.4.5 BART requirements for Regional Haze visibility impairment 

The state must submit an implementation plan containing emission limitations representing 

BART and schedules for compliance with BART for each BART-eligible source that may 

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

area, unless the state demonstrates that an emissions trading program or other alternative will 

achieve greater reasonable progress toward natural visibility conditions. To address the 

requirements for BART, the state must submit an implementation plan containing the following 

elements and include documentation for all required analyses: 

• A list of all BART-eligible sources within the state. 

• A determination of BART for each BART-eligible source in the state that emits any air 

pollutant which may reasonably be anticipated to cause or contribute to any impairment 

of visibility in any Class I area. All such sources are subject to BART. 

• If technological or economic limitations on the applicability of measurement 

methodology to a particular source would make an emission standard infeasible, the state 

may prescribe a design, equipment, work practice, or other operational standard, to 

require the application of BART. The emission standard establishes the emission 
14

reduction to be achieved by implementation of such alternative, and must provide for 

compliance by means which achieve equivalent results. 

• A requirement that each source subject to BART be required to install and operate BART 

as expeditiously as practicable, but not later than 5 years after approval of the 

implementation plan revision. 

• A requirement that each source subject to BART maintain the required control equipment 

and establish procedures to ensure such equipment is properly operated and maintained. 

A state may opt to implement an emissions trading program or other alternative measure rather 

than to require sources subject to BART to install, operate, and maintain BART. To do so, the 

state must demonstrate that the emissions trading program or other alternative measure will 

achieve greater reasonable progress than would be achieved through the installation and 

operation of BART. To make this demonstration, the state must submit an implementation plan 

containing the following plan elements and include documentation for all required analyses: 

• A demonstration that the emissions trading program or other alternative measure will 

achieve greater reasonable progress than would have resulted from the installation and 

operation of BART at all sources subject to BART in the state. 

• A demonstration that the emissions trading program or alternative measure will apply, at 

a minimum, to all BART-eligible sources in the state. Sources having a federally 

enforceable emission limitation meeting BART do not need to meet the requirements of 

the emissions trading program or alternative measure. 

• A requirement that all necessary emission reductions take place during the period of the 

first long-term strategy for Regional Haze. 

• A demonstration that the emission reductions resulting from the emissions trading 

program or other alternative measure will be surplus to those reductions resulting from 

measures adopted to meet requirements of the CAA as of the baseline date of the SIP. 

After a state has met the requirements for BART or implemented emissions trading program or 

other alternative measure that achieve more reasonable progress than the installation and 

operation of BART, BART-eligible sources will be subject to the core requirements for the 

Regional Haze implementation plan described above. 

Any BART-eligible facility required to install, operate, and maintain BART may apply to the 

Administrator for an exemption from that requirement, subject to the exemptions from control 

requirements described above. 

How does this provision relate to BART at taconite facilities? 

This provision requires the MPCA to submit a SIP containing emission limitations representing 

BART and schedules for compliance with BART for each BART-eligible source that may 
15

reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I area, 

unless it demonstrates that an emissions trading program or other alternative will achieve greater 

reasonable progress toward natural visibility conditions. 

This provision requires taconite facilities to determine BART for each BART-eligible source that 

emits any air pollutant which may reasonably be anticipated to cause or contribute to any 

impairment of visibility in any Class I area, unless the state has demonstrated that an emissions 

trading program or other alternative will achieve greater reasonable progress toward natural 

visibility conditions. For each source subject to BART, the facilities will be required to install 

and operate BART as expeditiously as practicable, but not later than 5 years after approval of the 

implementation plan revision. 

In the event that the MPCA opts to implement an emissions trading program or other alternative 

measure rather than require sources subject to BART to install, operate, and maintain BART, this 

provision requires the Agency to submit a SIP to demonstrate that this emissions trading program 

or other alternative measure will achieve greater reasonable progress than would be achieved 

through the installation and operation of BART. 

3.2.4.6 Requirements for comprehensive periodic revisions of implementation plans for 

Regional Haze 

Each state must revise and submit its Regional Haze implementation plan revision to EPA by 

July 31, 2018 and every ten years thereafter. In each plan revision, the state must evaluate and 

reassess all of the elements required in the Regional Haze implementation plan, taking into 

account improvements in monitoring data collection and analysis techniques, control 

technologies, and other relevant factors. In evaluating and reassessing these elements, the state 

must address the following: 

• Current visibility conditions for the most impaired and least impaired days, and actual 

progress made towards natural conditions during the previous implementation period. 

The period for calculating current visibility conditions is the most recent five-year period 

preceding the required date of the implementation plan submittal for which data are 

available. Current visibility conditions must be calculated based on the annual average 

level of visibility impairment for the most and least impaired days for each of these five 

years. Current visibility conditions are the average of these annual values. 

• The effectiveness of the long-term strategy for achieving reasonable progress goals over 

the prior implementation period(s); and 

• Affirmation of, or revision to, the reasonable progress goal. 

How does this provision relate to BART at taconite facilities? 

This provision requires the MPCA to revise and submit its Regional Haze SIP revision to EPA 

by July 31, 2018 and every ten years thereafter. The provision establishes the elements the 

MPCA must address in each plan revision. Although not specifically stated, this provision may 

be interpreted to require facilities to reevaluate BART every 10 years. 
16

3.2.4.7 Requirements for periodic reports describing progress towards the reasonable 

progress goals 

Each state must submit a report to the Administrator every 5 years evaluating progress towards 

the reasonable progress goal for each Class I area located within the state and in each Class I area 

located outside the state which may be affected by emissions from within the state. The first 

progress report is due 5 years from submittal of the initial implementation plan. 

How does this provision relate to BART at taconite facilities? 

This provision relates to MPCA and as such does not directly relate to BART at taconite 

facilities. 

3.2.4.8 Determination of the adequacy of existing implementation plan 

At the same time the state is required to submit any 5-year progress report, the state must also 

determine the adequacy of existing implementation plan and take action based upon the 

information presented in the progress report: 

1. If the MPCA determines that the existing SIP requires no further revision in order to achieve 

established goals for visibility improvement and emissions reductions, it must provide to the 

EPA a negative declaration that further revision is not needed at this time. 

2. If the MPCA determines that the SIP is or may be inadequate to ensure reasonable progress 

due to emissions from sources in another state(s) which participated in a regional planning 

process, it must provide notification to the EPA and to the other state(s) which participated in 

the regional planning process with the states. The MPCA must also collaborate with the other 

state(s) to develop additional strategies to address the plan's deficiencies. 

3. Where the MPCA determines that the SIP is or may be inadequate to ensure reasonable 

progress due to emissions from sources in another country, it must provide notification to the 

EPA. 

4. Where the MPCA determines that the SIP is or may be inadequate to ensure reasonable 

progress due to emissions from sources within the state, it must revise its SIP to address the 

plan's deficiencies within one year. 

How does this provision relate to BART at taconite facilities? 

This provision relates to MPCA and as such does not directly relate to BART at taconite 

facilities. 

3.2.4.9 Requirements for State and Federal Land Manager coordination 

By November 29, 1999, the state must have identified in writing to the FLMs the title of the 

official to which the FLM can submit recommendations on the implementation Regional Haze 

program requirements. The state must provide the FLM with an opportunity for consultation on 

an implementation plan (or plan revision) for Regional Haze. The state must include a 

description in any implementation plan (or plan revision) of how it addressed any comments 

provided by the FLMs. The plan (or plan revision) must provide procedures for continuing 
17

consultation between the state and FLM on the implementation of the visibility protection 

program. 

How does this provision relate to BART at taconite facilities? 

This provision establishes the required coordination between the MPCA and the FLMs. This 

provision relates to MPCA and as such does not directly relate to BART at taconite facilities. 

3.2.5 40 CFR 51.309 Requirements for the GCVTC 

This section establishes the requirements for the first Regional Haze implementation plan to 

address Regional Haze visibility impairment in the 16 Class I areas covered by the Grand 

Canyon Visibility Transport Commission (GCVTC) report. 

How does this provision relate to BART at taconite facilities? 

The Class I areas that are relevant to the taconite industry in Minnesota are not expected to be 

among the 16 Class I areas in the southwest United Stated covered by the GCVTC report. 

Therefore, this provision has no direct implication on the implementation of BART at taconite 

facilities. 

3.3 Status of Minnesota Implementation Plan for Visibility Protection 

Per 40 CFR 52.1236, the MPCA has not addressed visibility protection to EPA’s satisfaction, so 

40 CFR 52.26, 52.28, and 52.29 are incorporated. While Minnesota does not have a visibility 

protection plan7 that meets CAA Section 169a, the MPCA recognizes Regional Haze as an 

emerging issue that will necessitate implementation plan revisions8. Based on a review of the 

Minnesota SIP as summarized on 52.1220, no implementation plan documents have been 

submitted to the EPA concerning visibility. 

3.4 Implementation of the Regional Haze Program in Indian Country 

This section discusses how the requirements of the Regional Haze rule relate to emissions 

released from Indian Country. 

3.4.1 Background on Tribal Air Quality Programs 

On November 8, 1984, EPA released a policy statement entitled “EPA Policy for the 

Administration of Environmental Programs on Indian Reservations.” Under this policy, EPA will 

pursue the principle of Indian “self-government” and work with tribal governments on a 

“government-to-government” basis. The CAA, as amended in 1990, added a new section 

authorizing EPA to “treat tribes as states” for the purposes of administering CAA programs. The 

section required EPA to promulgate regulations listing specific CAA provisions for which it 

would be appropriate to treat tribes as states. These regulations are codified as 40 CFR part 49, 

generally referred to as the Tribal Authority Rule (TAR). The section also required EPA to 

 

7

 Per 40 CFR 52.1236(a)-(c). 

8

 Minnesota State Implementation Plan, 2002 Update. See http://www.pca.state.mn.us/air/sip.html. 
18

provide alternative means to ensure air quality protection in cases where it determines that 

treating tribes as “identical” to states would be inappropriate. In promulgating the TAR, EPA 

provided flexibility to tribes seeking to implement the CAA with the decision not to treat tribes 

as states for certain provisions of the CAA. For example, unlike states, tribes are not required by 

the TAR to adopt and implement CAA plans or programs and therefore are not subject to 

statutory deadlines for submittal of implementation plans. 

3.4.2 Issues Related to the Regional Haze Program in Indian Country 

The requirements of the Regional Haze rule are among those Federal air quality programs for 

which tribes may be determined eligible and receive authorization to implement under the TAR. 

Tribes wishing to participate in the Regional Haze program and be “treated as states” may seek 

approval but are not required to do so. Where tribes do not take on this responsibility, EPA will 

ensure air quality protection in Indian country consistent with TAR. 

In order to encourage tribes to participate, the TAR provides flexibility of submitting programs 

as they are developed, rather than in accordance with statutory deadlines. This means that tribes 

may take additional time as necessary to submit implementation plans for Regional Haze beyond 

the deadlines established in the rule. 

How does this provision relate to BART at taconite facilities? 

An Indian tribe may wish to participate in a state or regional planning effort for Regional Haze 

or develop its own self-sufficient Regional Haze program through an implementation plan 

referred to as a tribal implementation plan (TIP). The EPA is encouraging the consideration of 

impacts on visibility in tribal locations in regional planning efforts. 

In Minnesota, there are 11 Indian reservations or communities – seven Anishinaabe (Chippewa, 

Ojibwe) reservations and four Dakota (Sioux) communities (see Figure 3-2 for locations).9

 The 

seven Anishinaabe reservations include: 

1. Grand Portage located in the northeast corner of the state, 

2. Bois Forte located in extreme northern Minnesota, 

3. Red Lake located in extreme northern Minnesota west of Bois Forte, 

4. White Earth located in northwestern Minnesota, 

5. Leech Lake located in the north central portion of the state, 

6. Fond du Lac located in northeast Minnesota west of the city of Duluth, and 

7. Mille Lacs located in the central part of the state, south and east of Brainerd. 

The four Dakota Communities are in central and southern Minnesota and include: Shakopee 

Mdewakanton located south of the Twin Cities near Prior Lake; Prairie Island located near Red 

Wing; Lower Sioux located near Redwood Falls; and Upper Sioux located near the city of 

Granite Falls.

 

9

 Information from the Minnesota Indian Affairs Council at http://www.indians.state.mn.us/tribes.html. 
19

Figure 3-2. Locations of Indian Reservations, Federal Class I Areas, and Taconite Plan
20

4 Summary of BART Guidelines Proposed Rule 

The information provided in this section is based on EPA’s July 20, 2001 “Proposed Guidelines 

for Best Available Retrofit Technology (BART) Determinations Under the Regional Haze 

Regulations; Proposed Rule.”10 See Attachment F for a copy of the Federal Register notice. 

Section 4.1 provides context to the BART requirements as they relate to the CAA requirements. 

Section 4.2 details the BART requirements and Section 4.3 outlines the current legal challenges 

to the BART guidelines rulemaking. 

4.1 Background 

EPA included in the final Regional Haze rule, published on July 1, 1999, a requirement for 

BART for certain large stationary sources put in place between 1962 and 1977. In addition, 

Section 169a(b)(1) of the CAA requires EPA to provide guidelines to states on the 

implementation of the visibility program. The July 20, 2001 proposed BART rule would require 

states to use the guidelines for all of the 26 industry source categories. 

4.2 Guidelines for BART Determinations Under the Regional Haze 

Rule 

4.2.1 Overview 

Section 169a(b)(2)(A) of the CAA requires states to require certain existing stationary sources to 

install BART. The BART requirement applies to major stationary sources from one of 26 

identified source categories which have the potential to emit 250 tons per year or more of any air 

pollutant. The CAA requires sources which were put in place between August 7, 1962 and 

August 7, 1977 to install BART. The CAA requires BART when any source meeting the above 

description emits any air pollutant which may reasonably be anticipated to cause or contribute to 

any impairment of visibility in any Class I area. The CAA further requires states to make BART 

emission limitations part of their SIPs. 

In the July 1, 1999 rulemaking, EPA added a BART requirement for Regional Haze. The 

Regional Haze rule codifies and clarifies the BART provisions in the CAA. The rule requires 

states to identify and list BART-eligible sources. The next step is to identify those BARTeligible sources that may “emit any air pollutant which may reasonably be anticipated to cause or 

contribute to any impairment of visibility.” A source which fits this description is “subject to 

BART.” For each source subject to BART, states must identify the level of control representing 

BART (if any). Then it must establish an emission limit representing BART and ensure 

compliance with that requirement no later than 5 years after EPA approves the SIP. 

States have the option of using an alternative measure, such as an emissions trading program, to 

impose controls on a case-by-case basis for each source subject to BART. However, if states 

choose this option, they must provide a demonstration that the alternative will achieve greater 

 

10 66 FR 38108. 
21

“reasonable progress” than would have resulted from installation of BART. States are required to 

include in their SIPs details on how they would implement the alternative measure. 

The guidelines provide procedures states must use in implementing the Regional Haze BART 

requirements on a source-by-source basis. The guidelines address general topics related to 

development of a trading program or other alternative, but most of the details of guidance for 

trading programs will be addressed in separate rulemakings or policy documents. The BART 

analysis process is as follows: 

• Identification of all BART-eligible sources, 

• Identification of sources subject to BART, 

• Engineering analysis, 

• Cumulative air quality analysis, 

• Emissions limits, and 

• General considerations in establishing a trading program alternative. 

The guidelines are written primarily for the benefit of state, local, and tribal agencies to satisfy 

the requirements for including the BART determinations and emission limitations in their SIPs 

or tribal implementation plans (TIPs). 

4.2.2 How to Identify BART-Eligible Sources 

This section details the four steps to identify BART-eligible sources11. A BART-eligible source 

is an existing stationary source in 26 listed categories which meets criteria for startup dates and 

potential emissions. 

Step 1: Identify the emission units in BART categories.

The BART requirement only applies to sources in 26 specific categories listed in the CAA. The 

listed categories are: 

1. Fossil-fuel fired steam electric plants of more than 250 million British thermal units (BTU) 

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, 

 

11 See also Section 5.7.1 for a discussion of the MPCA BART survey. 
22

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 BTUs 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, and 

26. Charcoal production facilities. 

For Step 1, identify all of the emissions units at the plant that fit into one or more of the listed 

categories. At taconite plants, it is likely that there will be little confusion in how to classify 

emission units into their source categories, since most emission units at these plants can be 

classified into the “taconite ore processing facilities” source category. 

Step 2: Identify the start-up dates of those emission units.

Emissions units listed under Step 1 are BART-eligible only if they were “in existence” on 

August 7, 1977 but were not “in operation” before August 7, 1962. “In existence” means the 

same thing as the term “commence construction” as that term is used in the PSD regulations. “In 

operation” is defined as “engaged in activity related to the primary design function of the 

source.” This means that a source must have begun actual operations by August 7, 1962 to 

satisfy the BART eligibility requirement. 

The definition of BART-eligible facility includes sources that were in operation before August 7, 

1962, but were reconstructed during August 7, 1962 to August 7, 1977. A reconstruction has 

taken place if “the fixed capital cost of the new component exceeds 50 percent of the fixed 

capital cost of a comparable entirely new source,” the same policies and procedures for 

identifying reconstructed “affected facilities” under the New Source Performance Standard 

(NSPS) program. Similarly, if an emission unit has undergone reconstruction that commenced 

after August 7, 1977, it is not BART-eligible. 

The BART provision in the Regional Haze rule contains no explicit treatment of modifications. 

EPA believes the best interpretation for purposes of the visibility provisions is that modified 

emissions units are still “existing.” If a modification to an emissions unit which began operation 

within the 1962 to 1977 time frame was a major modification subject to the BACT, LAER, or 

NSPS levels of control, the review process will take into account that this level of control is 

already in place and may find that the level of controls are already consistent with BART. 
23

Step 3: Compare the potential emissions to the 250 ton/yr threshold.

The result of Steps 1 and 2 is a list of emissions units at a given plant site that are within one or 

more of the BART categories and that were placed into operation within the 1962 to 1977 time 

frame. The third step is to determine whether the total emissions represent a current potential to 

emit that is greater than 250 tons per year of any single visibility impairing pollutant. In most 

cases, total emissions are calculated as the sum of potential emissions from all emission units on 

the list resulting from Steps 1 and 2. In a few cases, a determination was made as to whether the 

plant contained more than one “stationary source”, explained further below. 

Visibility-impairing pollutants include the following: 

• Sulfur dioxide (SO2), 

• Nitrogen oxides (NOx), 

• Particulate matter,12

• Volatile organic compounds (VOC), and 

• Ammonia. 

The definition of potential to emit is identical to that in the PSD program. This means that a 

source which actually emits less than 250 tons per year of a visibility-impairing pollutant is 

BART-eligible if its emissions would exceed 250 tons per year when operating at its maximum 

physical and operational design. A source’s “potential to emit” may take into account federally 

enforceable emission limits. 

The Regional Haze rule defines a stationary source as a “building, structure, facility or 

installation which emits or may emit any air pollutant.” The rule further defines “building, 

structure or facility” as: all of the pollutant-emitting activities which belong to the same 

industrial grouping, are located on one or more contiguous or adjacent properties, and are under 

the control of the same person (or persons under common control). These plant boundary issues 

and “common control” issues are very similar to those already addressed in implementation of 

the Title V operating permits program (see 40 CFR 70) and in new source review (see 40 CFR 

52.21). For purposes of the Regional Haze rule, group emissions from all emission units put in 

place within the 1962 to 1977 time frame that are within the 2-digit SIC code, even if those 

emission units are in different categories on the BART category list. Taconite plants may have 

emission units classified outside the taconite ore processing source category and fit in another 

BART category (e.g., fossil-fuel boilers of more than 250 million BTUs per hour heat input). 

Therefore, taconite companies should ensure that the stationary source(s) is defined appropriately 

for determining BART eligibility of its emission units. 

 

12 66 FR 38119. PM10 may be used as the indicator for particulate matter. EPA does not recommend using total 

suspended solids. PM10 emissions include the components of PM2.5 as a subset. 
24

Step 4: Identify the emissions units and pollutants that constitute the BART-eligible source.

If the emissions from the list of emissions units at a stationary source exceed a potential to emit 

of 250 tons per year for any visibility-impairing pollutant, then that collection of emissions units 

is a BART-eligible source. A BART analysis is required for each visibility-impairing pollutant 

emitted. 

4.2.3 How to Identify Sources “Subject to BART” 

After identifying the BART-eligible sources, the next step is determining whether these sources 

are subject to a further BART analysis because they emit “an air pollutant which may reasonably 

be anticipated to cause or contribute” to any visibility impairment in a Class I area. A BARTeligible source is “reasonably anticipated to cause or contribute” to Regional Haze if the source 

emits pollutants within a geographic region from which pollutants can be emitted and transported 

downwind to a Class I area. 

EPA states, in general, that geographic “regions” that can contribute to Regional Haze generally 

extend for hundreds or thousands of kilometers. Because the taconite plants in Minnesota are 

located in relative close proximity to Class I areas, BART-eligible sources at these plants are 

initially presumed to be subject to BART. 

4.2.4 Engineering Analysis of BART Options 

In the Regional Haze rule, the BART analysis is divided into two parts: an engineering analysis 

requirement and a visibility impacts analysis requirement. This section of the guidelines 

addresses the requirements for the engineering analysis. The requirements for a visibility impacts 

analysis are discussed in Section 4.2.5. 

The engineering analysis identifies the best system of continuous emission reduction taking into 

account: 

• The available retrofit control options, 

• Any pollution control equipment in use at the source, 

• The costs of compliance with control options, 

• The remaining useful life of the facility, and 

• The energy and non-air quality environmental impacts of control options. 

In the proposed guidelines, EPA seeks comment on two alternative approaches for conducting a 

BART engineering analysis. Under the first approach, the BART analysis would be very similar 

to the BACT review using a “top-down” approach. The BART engineering analysis would be a 

process which ranks all available control technologies in descending order of control 

effectiveness. Under this option, the most stringent alternative must be examined first. That 
25

alternative is selected as the “best” unless demonstrated that the alternative cannot be justified 

based upon technical considerations, costs, energy impacts, and non-air quality environmental 

impacts. If the most stringent technology is eliminated in this fashion, the next most stringent 

alternative is then considered, and so on. The “top-down” approach is similar to the existing 

requirements for the Best Available Control Technology (BACT) in EPA’s New Source Review 

rules at 40 CFR 52.21. The second approach provides more choices in the way the BART 

analysis is structured. For example, the BART determination process could begin with the 

evaluation of the least stringent technically feasible control option or an intermediate control 

option drawn from the range of technically feasible control alternatives. Then the additional 

emission reductions, costs, and other effects (if any) of successively more stringent control 

options would be considered. 

While both approaches require essentially the same parameters and analyses, the EPA prefers the 

first approach, because it may be more straightforward to implement than the alternative and 

would tend to give more thorough consideration to stringent control alternatives. As a result, the 

BART screening evaluation in Section 7 is performed using the “top-down” approach. 

Although very similar in process, BART reviews differ in several respects from the BACT 

review process, as described in Table 4-1. 

Table 4-1 

BART Review vs. BACT Review 

BART Review BACT Review 

Applies to existing sources, which affects available 

controls and the impacts of those controls 

Applies to new sources, which affects available controls 

and the impacts of those controls 

State must take into account the “cost of compliance, 

the remaining useful life of the source, the energy and 

non-air quality environmental impacts of compliance, 

any existing pollution control technology in use at the 

source, and the degree of improvement in visibility 

from the use of such technology” 

Permitting authority must consider the “energy, 

environmental and economic impacts and other costs” 

associated with a control technology 

Because of the differences in terminology, the BART 

review process tends to encompass a narrower range 

of factors (e.g., “non-air quality environmental 

impacts”) 

Because of the differences in terminology, the BACT 

review process tends to encompass a broader range of 

factors (e.g., “environmental impacts”) 

No requirement in the BART engineering analysis to 

evaluate adverse air quality impacts of control 

alternatives such as the relative impacts on hazardous 

air pollutants 

Requirement in the BACT engineering analysis to 

evaluate adverse air quality impacts of control 

alternatives such as the relative impacts on hazardous 

air pollutants 

No minimum level of control required BACT emission limitation must be at least as stringent 

as any NSPS that applies to the source 

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

visibility-impairing pollutant emitted. In a BART review, BART must be established for each 

pollutant that can impair visibility for each affected emission unit. Consequently, the BART 
26

determination must address air pollution control measures for each emissions unit or pollutant 

emitting activity subject to review. 

The five basic steps of a case-by-case BART engineering analysis are: 

Step 1: Identify all available retrofit control technologies, 

Step 2: Eliminate technically infeasible options, 

Step 3: Rank remaining control technologies by control effectiveness, 

Step 4: Evaluate impacts and document the results, and 

Step 5: Select “best system of continuous emission reduction.” 

These steps are detailed in the taconite industry BART screening evaluation presented in Section 

7 of this report. 

4.2.5 Cumulative Air Quality Analysis 

The Regional Haze rule requires the following in 40 CFR 51.308(e)(1)(ii)(B): 

An analysis of the degree of visibility improvement that would be achieved in each 

mandatory Class I Federal area as a result of the emission reductions from all sources 

subject to BART located within the region that contributes to visibility impairment in the 

Class I area, based on the... [results of the engineering analysis required by 40 CFR 

51.308(e)(1)(ii)(A)]. 

A regional modeling analysis is required to address the total cumulative regional visibility 

improvement if all sources subject to BART were to install the “best” controls selected according 

to the engineering analysis described above in Section 4.2.4. 

The regional modeling analysis is used to assess the cumulative impact on visibility of the 

controls selected in the engineering analysis for the time period for the first Regional Haze SIP, 

that is, the time period between the baseline period and the year 2018. This cumulative impact 

assessment is used to determinate whether the controls identified provide sufficient visibility 

improvement to justify their installation. There is sufficient basis for the controls if it is 

demonstrated for any Class I area that any of the following criteria are met: 

1. The cumulative visibility improvement is a substantial fraction of the achievable visibility 

improvement from all measures included in the SIP, or is a substantial fraction of the 

visibility goal selected for any Class I area; or 

2. The cumulative visibility improvement is necessary to prevent any degradation from current 

conditions on the best visibility days. The visibility SIP must provide for BART emission 

limitations for all sources subject to BART, unless it is demonstrated that no BART controls 

are justifiable based upon the cumulative visibility analysis. 
27

4.2.6 Enforceable Limits / Compliance Date 

To complete the BART process, enforceable emission limits must be established and compliance 

is required within a given period of time. In particular, an enforceable emission limit must be 

established for each emission unit and each pollutant subject to review. In addition, compliance 

with the BART emission limitations must be required no later than 5 years after EPA approves 

the SIP. If technological or economic limitations in the application of a measurement 

methodology to a particular emission unit would make an emissions limit infeasible, a design, 

equipment, work practice, operation standard, or combination of these types of standards may be 

prescribed. 

Because the BART requirements are “applicable” requirements of the CAA, they must be 

included as Title V permit conditions. The CAA requires emissions limits such as BART to be 

met on a continuous basis. Although the CAA does not necessarily require the use of continuous 

emissions monitors (CEMs), it is important that sources employ techniques that ensure 

compliance on a continuous basis. Monitoring requirements generally applicable to sources, 

including those that are subject to BART, are governed by other regulations (e.g., 40 CFR 64 for 

compliance assurance monitoring; 40 CFR 70.6(a)(3) for periodic monitoring; 40 CFR 70.6(c)(1) 

for sufficiency monitoring). In addition, emissions limits must be enforceable as a practical 

matter (contain appropriate averaging times, compliance verification procedures, and 

recordkeeping requirements). In light of the above, the permit must: 

• Be sufficient to show compliance or noncompliance (i.e., through monitoring times of 

operation, fuel input, or other indices of operating conditions and practices); and 

• Specify a reasonable averaging time consistent with established reference methods, 

contain reference methods for determining compliance, and provide for adequate 

reporting and recordkeeping so that air quality agency personnel can determine the 

compliance status of the source. 

4.2.7 Emissions Trading Program Overview 

States have the option of implementing an emissions trading program or other alternative 

measure instead of requiring BART. This option provides the opportunity for achieving better 

environmental results at a lower cost than a source-by-source BART requirement. A trading 

program must include participation by BART sources, but may also include sources that are not 

subject to BART. The program would allow for implementation during the first implementation 

period of the Regional Haze rule (that is, by the year 2018) instead of the 5-year compliance 

period. The basic steps that the state would need to complete for an emissions trading program 

are: 

1. Develop emission budgets; 

2. Allocate emission allowances to individual sources; and 

3. Develop a system for tracking individual source emissions and allowances. 
28

MPCA has not formally decided whether to utilize an implementation plan with unit-specific 

BART limitations or an emissions trading program. However, the fact that the State is investing 

time and resources in a project to assess BART requirements for the taconite industry indicates 

that an implementation plan is the probable option that will be taken to meet Regional Haze 

requirements. 

4.3 Summary of Recent Court Rulings 

The information provided in this section is based on the May 24, 2002 District of Columbia 

(D.C.) Court of Appeals decision (no. 99-1348), American Corn Growers Association vs. EPA; 

the September 19, 2002 decision, American Corn Growers Association vs. EPA; and the 

September 8, 2003, Federal Register notice regarding a proposed Consent Decree between EPA 

and Environmental Defense. A copy of the May 24, 2002, Court of Appeals decision is located 

in Attachment G. 

4.3.1 May 2002 D.C. Circuit Court of Appeals Decision 

4.3.1.1 Background 

American Corn Growers Association and other industry petitioners, including groups 

representing coal companies, railroads, and coal-fired electric generators, filed an appeal over 

several issues in the Regional Haze rule. The petitioners claimed that: 

Claim #1. EPA acted contrary to the law in establishing a group rather than a source-by-source 

approach to BART determinations; 

Claim #2. EPA acted without legal authority and in an arbitrary and capricious manner by 

promulgating the “natural visibility goal” and “no degradation requirement;” and 

Claim #3. EPA failed to set reasonable criteria for measuring or assuring “reasonable progress,” 

and acted contrary to law in extending the statutory deadline for submission of the 

state Regional Haze control plans. 

The Sierra Club also requested a review of the “reasonable progress” criteria of the rule, arguing 

that the rule is an effective and cost-efficient method of controlling Regional Haze. 

On May 24, 2002, the D.C. Circuit Court of Appeals issued an opinion in the appeal of the 

Regional Haze Rule. The court determined that the portion of the rule addressing BART (Claim 

#1) contravened the CAA by not giving states enough discretion in applying it. However, the 

court upheld the EPA’s Regional Haze goals (Claim #2) and reasonable progress criteria (Claim 

#3). The court declined to rule on the “reasonable progress” issues brought by the Sierra Club, 

finding that they were premature. 

4.3.1.2 BART Issues 

Each state must determine BART for each source that emits a pollutant which may reasonably be 

anticipated to cause or contribute to Class I visibility impairment. Section 4.2.4 discusses the five 

statutory criteria that states must consider when deciding what BART controls to place on a 

source. They are: 
29

1. The costs of compliance, 

2. The energy and non-air quality environmental impacts of compliance, 

3. The existing pollution control technology in use at the source, 

4. The remaining useful life of the source, and 

5. The degree of improvement in visibility which may reasonably be anticipated to result from 

the use of such technology. 

The petitioners noted that while the rule requires states to address the first four criteria on a 

source-by-source basis, it requires the fifth criteria to be addressed on a group basis. A BARTeligible source is “‘reasonably anticipated to cause or contribute’ to Regional Haze if it can be 

shown that the source emits pollutants within a geographic area from which pollutants can be 

emitted and transported downwind to a Class I area.” In addition, the rule requires states to 

“assess the degree of visibility improvement that would be achieved in each Class I area on the 

basis of emission reductions achievable from all sources subject to BART located within the 

region that contributes to visibility impairment in the Class I area in the region of the Class I 

area.” The petitioners argued that using a group-basis rather than a source-by-source BART 

approach contravenes the language, statutory structure, and legislative history of Section 169a of 

the CAA and unlawfully constrains the states by requiring BART controls at sources without any 

empirical evidence of the particular source’s contribution to visibility impairment in a Class I 

area. 

EPA argued that its bifurcated approach to determining appropriate BART controls should be 

upheld because Section 169a is unclear about how a state must analyze anticipated visibility 

improvement. However, the court ruled agreed with the petitioners that treating one of the five 

factors differently was contrary to the language and structure of the CAA. All five factors were 

meant to be considered together to help the states determine what BART controls are 

appropriate. The court stated that this is most apparent with respect to the states’ duty to take into 

account “the costs of compliance” in deciding not only whether to order an individual source to 

install any new pollution control equipment, but also what type of equipment: the only way for 

states to determine whether the costs are appropriate is to compare the costs to the individual 

source with the degree of visibility improvement from installing controls at that source. The 

court found that under EPA’s approach, it is entirely possible that a source may be forced to 

spend millions of dollars for new technology that will have no appreciable effect on the haze in 

any Class I area. 

The court also upheld that the BART provisions are inconsistent with the CAA’s provisions 

giving the states broad authority over BART determinations. The rule unlawfully constrains the 

states’ statutory authority because under the CAA it is the states - not EPA - who must determine 

which BART-eligible sources should be subject to BART. The rule requires BART controls 

based simply on a finding that a source could affect a Class I area, thus giving the states no 

authority to determine the appropriate controls for each source. The court cited the Conference 

Report on the 1977 amendments to the CAA, which states that the states, not EPA, shall 

determine what constitutes BART. The court also noted that if the rule contained some kind of a 

mechanism by which a state could exempt a BART-eligible source on the basis of an 
30

individualized contribution determination, then perhaps the meaning of the CAA would not be 

violated. 

Thus, the court held that the BART provisions of the Regional Haze rule are impermissible. 

4.3.1.3 “Natural Visibility” Goal and “No Degradation” Requirement 

The industry petitioners cited four arguments in support of their claim that the “natural visibility” 

goal and the “no degradation” requirement in the Regional Haze rule should be vacated as 

“arbitrary and capricious”: 

1. EPA exceeded its authority under Section 169a and adopted regulations that conflict with the 

Prevention of Significant Deterioration (PSD) program in establishing “natural visibility” as 

the goal of the Regional Haze program; 

2. The regulations impermissibly constrain state discretion in requiring that the states develop 

their visibility programs using the “no degradation” requirement as a benchmark; 

3. EPA has no authority to impose upon the states the goal of achieving “natural visibility” 

conditions, and thereby restrict the opportunity of some states to participate in the planning 

process aimed at addressing Regional Haze; and 

4. EPA promulgated the rule without providing adequate notice and an opportunity for 

comment. 

EPA claimed that petitioners’ challenge to the natural visibility goal and their claims of 

inadequate notice were not properly raised. The court found no merit in EPA’s contentions. 

However, the court also found no merit in industry petitioners’ claims and therefore denied their 

challenge to the “natural visibility” goal and the “no degradation” requirement as neither 

manifestly contrary to the statute nor arbitrary or capricious in substance. 

Petitioners claimed that the natural visibility goal and the no degradation requirement are 

contrary to the PSD program, because that program recognizes that some impairment of visibility 

would be acceptable in Class I areas. The court rejected this argument because the CAA creates a 

national goal of remedying visibility impairment and the Regional Haze rule complements that 

goal. Furthermore, the court believes the PSD program does not create an entitlement to degrade 

visibility. 

Petitioners also argued that because states must determine the “reasonable progress” sources 

should make in enhancing visibility, and that reasonable progress could sometimes require 

visibility degradation, the no degradation requirement restricts states’ authority to apply the 

statutory criteria. The court found this claim incorrect because the no degradation requirement 

simply elucidates “reasonable progress,” which does not include the possibility of visibility 

degradation. 

Petitioners also asserted that the Regional Haze rule somehow restricts the opportunity of some 

states to participate in the planning process aimed at addressing Regional Haze, the court found 

no real evidence in support of this claim. 

Finally, petitioners claimed that they did not have fair notice and adequate opportunity to 

comment on the regulatory goal of natural visibility. The court found this argument to be without 
31

merit. The court found that industry had received adequate notice because there was no material 

inconsistency between the statutory goal of 169a and the regulatory goal of “natural visibility.” 

4.3.1.4 “Reasonable Progress” Criteria and the Extension of the Statutory Deadline 

The Sierra Club argued that the Regional Haze rule’s requirements for improvement in visibility 

during the 20 percent most impaired days and for no degradation during the 20 percent least 

impaired days do not qualify as “reasonable progress” criteria and are arbitrary and capricious. 

The court held that the issue is unripe for review because the BART issue was remanded, and 

because EPA could change its criteria for evaluating reasonable progress on remand. 

The Sierra Club also argued that the provision in the rule allowing states 3 years to file Regional 

Haze SIPs for areas designated “attainment” or “unclassifiable” violated the CAA. The 

Transportation Equity Act for the 21st Century (TEA–21) provisions establish and link deadlines 

for the Regional Haze SIPs and PM2.5 monitoring and area designations. TEA-21 provides that 

for areas designated as “attainment” or “unclassifiable”, EPA must require SIPs to be submitted 

1 year after the area has been designated. Although the court expressed doubts about the validity 

of the three-year deadline, it remanded the issue with the group-BART provisions. 

4.3.2 September 2002 D.C. Circuit Court of Appeals Decision 

Based on the decision reached on May 24, 2002 by the D.C. Circuit Court of Appeals that the 

portion of the Regional Haze rule addressing BART contravened the CAA by not giving states 

enough discretion in applying it, EPA petitioned the court for a rehearing. The court denied the 

petition on September 19, 2002, and the May decision will stand unless appealed successfully to 

the U.S. Supreme Court. 

4.3.3 August 2003 Proposed Consent Decree for BART Deadline 

In a September 8, 2003, Federal Register notice,13 EPA is requesting written comments by 

October 8, 2003, regarding a proposed Consent Decree. On August 15, 2003, Environmental 

Defense filed a complaint alleging that EPA had failed to meet its mandatory duty to promulgate 

BART regulations. On August 19, 2003, EPA lodged the proposed Consent Decree with the 

United States District Court for the District of Columbia Circuit. 

The proposed Consent Decree provides that EPA will sign a notice of proposed rulemaking 

setting forth its proposed BART regulations and guidelines no later than April 15, 2004, with 

submittal to the Office of Federal Register no later than five days following signature. The 

Decree also establishes an April 15, 2005, deadline for signing a final notice of rulemaking, with 

submittal to the Office of Federal Register no later than five days following signature. See 

Table 3-2 for the relationship between these proposed regulatory deadlines and the anticipated 

timeline for compliance with BART. 

 

13 68 FR 52922 
32

5 Taconite Industry Overview and BART-Eligible Source 

Identification 

MPCA has identified the taconite industry as an industry requiring an analysis to identify the 

impacts of the federal Regional Haze rule. Barr has completed a BART screening evaluation in 

Sections 6 and 7 identifying and summarizing the feasibility of control options for the taconite 

industry. This evaluation will serve as a tool and template consistent with EPA’s proposed 

BART guidance. As a first step before performing the BART screening evaluation, Sections 5.1 

through 5.7 provide an overview of the taconite industry and Sections 5.8 and 5.9 identifies and 

categorizes BART-eligible units at Minnesota taconite plants. 

Some of the information provided in Sections 5.1 through 5.5 is based on MPCA’s December 30, 

1999 “Taconite Iron Ore Industry in the United States” report. 

5.1 Iron Ore Ranges 

Iron ore is mined and processed in the U.S. mainly on the Mesabi Range of northern Minnesota 

and the Marquette Range of the Upper Peninsula of Michigan. The Mesabi Range is located 

approximately 65 miles north of Duluth, MN. The range is approximately 120 miles long from 

Grand Rapids to Babbitt with a thickness of 400 to 750 feet. The iron-ore material that is mined, 

concentrated, and pelletized is magnetite (Fe3O4), or magnetic taconite. The Marquette Range is 

located in the northern part of the Upper Peninsula of Michigan with its eastern end 10 miles 

west of the Lake Superior port of Marquette. The range is approximately 30 miles long and 6 

miles wide. The iron-ore material that is mined, concentrated, and pelletized is magnetite and 

hematite (Fe2O3). 

5.2 Taconite Mining and Processing Facilities 

This report focuses on the six active taconite mining and processing facilities located on the 

Mesabi Range of Minnesota. The facilities are: EVTAC Mining, LLC, (Mine and Plant), 

Hibbing Taconite Company, Ispat-Inland Steel Mining Company, Keewatin Taconite, 

Northshore Mining Company (Mine and Plant), and U.S. Steel Minnesota Ore Operations. 

Operations at the taconite facilities vary based on several factors, including when the facility was 

built and what technology was available, the type of crude ore the facility mines, and the type of 

pellet product the facility is making. These and other factors can affect the mining, crushing, 

concentrating, and pelletizing processes, which are described in more detail below. 

5.3 Taconite Pellets 

Taconite is a low-grade iron ore used to make taconite pellets. The iron in the taconite ore is 

composed of magnetic ore (magnetite) and non-magnetic ore (hematite and limonite). These 

forms of iron must be oxidized to be suitable for steel production. The taconite ore is crushed, 

and the iron is removed to produce a concentrate. Ore concentrate, a binding agent and other 

additives are mixed to form “green balls”. Green balls are 3⁄8 to 1⁄2 inches in diameter and have an 
33

iron content of approximately 65 % by weight. The green balls are oxidized and heat hardened at 

about 2,400 °F to produce taconite pellets. The finished product is shipped to steel mills for steel 

production. 

5.4 Mining 

The taconite ore is extracted in an open pit mine. First, the earth and rock on top of the ore 

(overburden) is removed. Drilling and blasting is necessary to remove the rock overburden. Soils 

and rock debris are removed with earthmovers, trucks and other heavy equipment and placed in 

storage areas. Next, the iron ore is removed. Drilling, blasting and materials handling equipment 

is necessary to remove the iron ore and transport it to the crusher where the crude ore is reduced 

to pieces sized at 10 inches or less. After crushing, the iron ore is transported to the pellet plant 

via conveyor, truck or rail for further processing. Emissions from mining are generally coarse 

fugitive dust produced in the mine pits, at ground level or slightly elevated sources. These 

emissions generally do not travel significant distances; so, they are not likely to have a 

significant impact on visibility. Most of the fugitive dust emissions are from the haul roads. 

Water suppression and chemical stabilization methods are generally used to control particulate 

emissions. 

All taconite plants have fugitive particulate emission management plans in place. These plans are 

prepared by each plant to control particulate emissions per MN rule 7011.0150. The control 

plans are reviewed by MPCA as part of the Title V permit re-issuance process, which occurs 

every five years. The plans must include control measures that are deemed reasonable for 

preventing particulate matter from becoming airborne per Minn. R. 7011.150, and are updated as 

needed within the permit review process. Since process for a dust control plan review is already 

in place, little can be gained in terms of further emission reductions via a BART evaluation. 

Therefore, no further analysis will be conducted on mining emissions in this study. 

5.5 Pellet Plant Overview 

In the pellet plant, the raw iron ore is crushed, concentrated, pelletized, and baked (via 

induration) to produce taconite pellets. 

5.5.1 Crushing 

Taconite ore must be finely crushed so that the iron ore can be extracted. Multi-stage crushing 

and grinding systems are used. Crushing systems often consist of a coarse crushing stage, which 

reduces the crude ore to 10 inch or smaller pieces, as well as a fine crushing stage, which further 

reduces the coarsely crushed ore to about 1 inch pieces. Most dry crushers are currently vented to 

particulate control equipment. 

5.5.2 Ore Grinding and Iron Separation 

Using water, the ore is further ground and milled to optimum particle size in rod and ball mills. 

Where water is used in the grinding process, no particulates are emitted. Magnetic separators 
34

separate the iron-bearing particles (concentrate) from the non-iron bearing particles (tailings). 

Other equipment used to form concentrate includes cyclones, hydro separators, screens, and 

flotation. Iron ore separation is a wet process and no particulates are emitted. 

5.5.3 Pelletizing 

The wet concentrate is mixed with a binder and other additives to form “soft” or “green” balls in 

balling machines. Since these processes are wet, they are not sources of particulate emissions. 

Binders and additives are stored as dry materials. Some particulate emissions are associated with 

material handling of the binders and additives. 

5.5.4 Induration 

The pellets are oxidized and heat-hardened in the induration furnace. Discharged pellets are 

cooled, screened, and transferred on conveyor belts to bins or stockpiles for storage. The stored 

pellets are loaded to ships or trains for shipment to the steel mill. 

Historically, three types of induration furnaces have been used in the taconite industry: straight 

grate, grate/kiln and vertical shaft furnaces. Only straight grate and grate/kiln induration furnaces 

are in operation at this time. One facility has inactive vertical shaft furnaces, and that facility 

does not anticipate operating the vertical shaft furnaces in the future. This study focuses on the 

two active types of induration furnaces. 

Figure 5-1 on the following page is a general diagram of a straight grate induration furnace. 

Figure 5-2 is a general diagram of a grate/kiln induration furnace. 
35

Figure 5-1. General Diagram of a Straight Grate Induration Furnace 

Courtesy: Hibbing Taconite Company 

Figure 5-2. General Diagram of a Grate/Kiln Induration Furnace. 

Cooling Air Fan 

Hood Exhaust 

Fan 

Windbox 

 Windbox Recoup Fan 

Exhaust Fan 

Updraft 

Drying Fan 

Green Pellets 

Enter Here 

Fired Pellets Exit 

Here 
36

The induration process involves pellet pre-heating, drying, hardening, oxidation and cooling. In a 

straight grate furnace, pellets move through the entire furnace on a traveling grate. In a grate/kiln 

furnace, 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. This temperature is required to meet taconite pellet product specifications. 

Fuel combustion in the induration furnace is carried out at 300 % to 400 % excess air to provide 

sufficient oxygen for pellet oxidation. 

Natural gas, fuel oil, sawdust, petroleum coke, and coal are fuel sources used in induration 

furnaces at the Minnesota taconite plants. The fuel is primarily combusted in the pellet hardening 

and oxidation section of the furnace. Fuel is also used in the pre-heat/drying section at some of 

the furnaces. 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. Pellet 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 with process constraints. Hot air from the 

pellet coolers is also used for fuel combustion, allowing for more of the fuel’s energy to be 

directed to the process instead of heating ambient air to combustion temperatures. 

Visibility-impairing pollutants emitted from the pelletizing operation include particulate matter, 

sulfur dioxide, nitrogen oxides, and volatile organic compounds. 

Nitrogen oxides (NOx) are formed by both the thermal oxidation of nitrogen in the combustion 

air and the reduction and subsequent oxidation of fuel bound nitrogen. The majority of NOx

emissions from a pellet plant are from thermal oxidation due to the high oxygen levels and high 

operating temperatures present in the induration furnaces. NOx emissions are released to the 

atmosphere in the induration furnace flue gas. 

Sulfur dioxide (SO2) emissions originate from both fuel combustion (depending on the sulfur 

content in the fuel used) and the oxidation of sulfur present in the green balls. SO2 emissions are 

released to the atmosphere in the induration furnace flue gas. 

Particulate matter emissions emanate from both fuel combustion, especially if a solid fuel is 

used, and the attrition of particles (dust) in the taconite pellets. Particulate emissions from the 

pellets are caused by the abrasion of pellets rubbing against each other and against the equipment 

as the pellets move through the induration furnace. Particulates are released to the atmosphere in 

the induration furnace flue gas and in the pellet cooler exhaust. 

Volatile organic compound emissions are formed by the incomplete combustion of fuels in the 

induration furnace. These emissions are negligible due to both the high oxygen levels and high 

operating temperatures present in the induration furnace. 

5.5.5 Material Handling 

Conveyors and mobile equipment (e.g. front end loaders) are used to transport the taconite ore, 

ore concentrate, pellets, pellet binding/blending materials, and solid fuels in the taconite plants. 
37

Particulate emissions are caused by wind blowing across conveyors, conveyor drops, and drops 

from mobile equipment. Many of these sources are either enclosed and/or connected to control 

devices to minimize particulate emissions. Fugitive emissions may also occur at storage piles of 

ore, ore concentrate and finished pellets. 

5.6 Boilers, Heaters, and Diesel Engines 

The taconite industry uses boilers and heaters to generate steam for pressurized steam power, 

process and space heating, and electricity generation. Diesel engines are used primarily for backup electricity generation. This equipment is not specific to the taconite industry; many industrial 

sectors use boilers, heaters, and diesel engines. As decided upon in the working group 

coordination meeting on March 18, 2003, this equipment will be reviewed as a separate BART 

source classification and are not included in this evaluation. 

5.7 Taconite Industry Emissions Data 

As discussed in Section 4.2.2, the visibility-impairing pollutants per the BART proposed 

guidelines14 are SO2, NOx, PM10, VOC, and NH3. 

For comparison purposes, total actual emissions of visibility-impairing pollutants from the six 

Minnesota taconite facilities and two Michigan facilities are provided below in Table 5-1. 15 In 

addition, the total limited potential to emit at Minnesota taconite facilities for each visibilityimpairing pollutant is shown in this table.16 Potential to emit data at Michigan taconite facilities 

are not readily available from the Michigan Department of Environmental Quality (MDEQ).17

 

14 66 FR 38107. 

15 The 2001 actual emissions data at Minnesota taconite facilities are taken from MPCA’s website 

(http://www.pca.state.mn.us/air/emissions/emissearch.cfm). The 2001 actual emissions data at Michigan taconite 

facilities are taken from MDEQ’s website (http://www.deq.state.mi.us/maers/emissions_query.asp). 16 The potential to emit data at Minnesota taconite facilities are provided by MPCA from their Delta database. 17 May 2, 2003 e-mail correspondence from Mr. Thomas Maki of Michigan Department of Environmental Quality to 

Mr. Joel Trinkle of Barr. 
38

Table 5-1 

Emissions of Visibility-Impairing Pollutants from the Eight U.S. Taconite Facilities by State

VisibilityImpairing 

Pollutant 

Minnesota 

2001 Actual Emissions 

(tons) 

Michigan 

2001 Actual Emissions 

(tons) 

Minnesota Limited 

Potential to Emit2

(tons) 

SO2 8,129 2,514 24,638 

NOx 27,636 9,829 76,707 

PM10 10,648 562 29,135 

VOC 177 103 2,118 

Ammonia NA1 NA1 NA1

1

 Ammonia is not reported in the Minnesota emission inventories and has only recently been added as a required 

reportable pollutant in Michigan for certain source classification codes. The EPA’s National Emissions Inventory 

(NEI) Version 2 reports ammonia emissions of 0.260 tons per year for a three-month period from one taconite plant 

in Minnesota. 

2

 Potential to emit data for the Northshore Mining Company’s Babbitt Mine are unavailable and have not been 

included. The only visibility-impairing pollutant emitted in a significant quantity under the BART guidelines (100 tpy) 

from this facility is PM10. Actual 2001 PM10 emissions from this facility are 176 tons. 

Table 5-1 indicates that VOC and ammonia are not emitted in significant quantities from the 

taconite plants. The BART screening study for the taconite industry focuses on SO2, NOx, and 

PM10 as the pollutants of concern. 

5.8 BART-Eligible Sources 

5.8.1 Initial MPCA BART Survey Request 

MPCA surveyed the Minnesota taconite facilities to establish a list of potential BART sources, 

based on pollutants emitted and dates in existence and in operation (see handout included in 

Attachment C). MPCA provided Barr with a summary of the returned BART surveys.18

5.8.2 Categorization of BART-Eligible Units at the Minnesota Taconite Plants 

An appropriate first step in evaluating BART for a group of sources is to categorize emission 

units within the “taconite ore processing facilities” source category. Grouping several emission 

units into a few categories will allow efficient evaluation of available control technology options 

for the industry. The regulatory study is based on three emission unit source types: 1) particulate 

fugitive sources, 2) particulate point sources, and 3) induration point sources. Particulate fugitive 

sources include unpaved roads, transfer conveyors, and stockpiles. Particulate point sources 

include ore conveyors, crushers, additive handling, pellet coolers, screens, and product 

conveyors. Induration point sources include straight grate furnaces and grate-kiln systems. Each 

 

18 Barr was not asked to verify the accuracy or completeness of the BART surveys. 
39

of the three emission categories includes multiple sources as shown in Table 5-2 below. Refer to 

handout included in Attachment C for categorization of BART-eligible sources. 

Table 5-2 

Emission Unit Categories at Taconite Ore Processing Facilities

Taconite Emission Unit Category Example Sources 

Particulate Fugitive Source Unpaved Roads 

Conveyors (transfer point not enclosed) 

Mobile Equipment 

Stockpiles 

Particulate Point Source Crushers 

Screens 

Conveyors (transfer point enclosed) 

Bins 

Blenders 

Grates 

Coolers 

Pellet Discharge 

Induration Point Source 

(Particulate and Combustion Emissions) 

Straight Grate 

Grate-Kiln 

The emission sources at taconite ore processing facilities are categorized into the three emission 

unit categories to facilitate both the selection of model sources in Section 5.8.3 for the BART 

screening evaluation and for the review of applicable air regulations in Section 9. 

5.8.3 Taconite Industry Model Sources 

In order to facilitate the BART screening evaluation of emission units at the taconite plants, Barr 

proposed to the working group at the March 18, 2003, working group coordination meeting that 

taconite emission units can be classified into five source categorizations: 

• Group 1: fugitive particulate-only sources, 

• Group 2: point particulate-only sources, 

• Group 3: induration point sources (induration furnace stacks), 

• Group 4: external combustion sources, and 

• Group 5: internal combustion sources. 

The focus of the BART screening evaluation is on the group 2 and group 3 sources. Group 1 

fugitive particulate-only sources are already required to meet dust control requirements under 

Minnesota rules, and they are not expected to contribute significantly to visibility impairment at 

Class I areas several miles away due to the relatively poor far-field atmospheric dispersion from 
40

low-lying stockpiles. As described in Section 5.6, groups 4 and 5 should be reviewed as a 

separate BART source classification and are not included in this evaluation. 

From source category groups 2 and 3, Barr chose four “model sources” to enable the 

development of representative control cost estimates. The four model sources are as follows: 

• Straight gate induration furnace, 

• Grate/kiln induration furnace, 

• Pellet cooler, and 

• Iron ore material handling. 

The physical characteristics of these model sources are summarized in Table 7-1. The model 

sources are selected to reflect emission units found at taconite facilities and that are specific to 

the taconite industry. As described in Section 5.5.4, straight grate and grate/kiln induration 

furnaces are chosen because they are the predominant types of furnaces at these plants. Pellet 

coolers are chosen because they are a common source of particulate matter. Iron ore material 

handling is chosen because it occurs in several phases of taconite plant operations and it 

represents many material handling emission points. The taconite industry source categories and 

model sources are summarized in Table 5-3. 
41

Table 5-3 

BART Eligible Source Classification for Taconite Industry Sources 

Primary Source Type Secondary Source Type 

Industrial 

Source Type 

BART 

Model 

Source 

1.00 Particulate Fugitive Source 1.01 Unpaved Roads Mine 

 1.02 Material Handling 

(Conveyor) 

Mine 

 1.03 Material Handling (Mobile 

Equipment) 

Mine 

 1.04 Material Handling (Other) Mine 

 1.03 Wind Erosion (Stockpile) Mine, Taconite 

 1.04 Wind Erosion (Other) Mine, Taconite 

2.00 Particulate Point Source 2.01 Crushing Taconite 

 2.02 Material Handling – Ore Taconite X 

 2.03 Material Handling – 

Additive 

Taconite 

 2.04 Material Handling – Coal Taconite 

 2.05 Straight Grate (Grate) Taconite 

 2.06 Straight Grate (Pellet 

Discharge) 

Taconite 

 2.07 Grate-Kiln (Grate) Taconite 

 2.08 Grate-Kiln (Cooler) Taconite X 

 2.09 Grate-Kiln (Pellet 

Discharge) 

Taconite 

 2.10 Material Handling – Pellets Taconite 

 2.11 Paint Gun Taconite 

3.00 Induration Point Source 3.01 Straight Grate (Induration) Taconite X 

 3.02 Grate-Kiln (Induration) Taconite X 

4.00 External Combustion 

Source 

4.01 Boiler (Electrical 

Generator) 

Ext. Combustion 

 4.02 Boiler Ext. Combustion 

 4.03 Heater (Make-up) Ext. Combustion 

 4.04 Zinc Melt Furnace Ext. Combustion 

5.00 Internal Combustion Source 5.01 Diesel Engine Int. Combustion 

The selection of model sources is based in part on the level of emissions at each source category. 

Emission inventory data from year 2001 at the Minnesota taconite plants are sorted by taconite 

source category for groups 2 and 3. Each source category summary is examined for the number 

of sources and emission rates associated with that category. 

Iron ore material handling is selected as the model source for PM emissions from Group 2. The 

other source categories in Group 2 are similar to ore handling. The primary difference between 

secondary source categories in Group 2 is the type of materials processed. The final BART 
42

evaluation that each facility will perform for Group 2 material handling emission units should be 

similar to the screening evaluation of the model iron ore material handling source. 

Pellet coolers are distinct source type within Group 2 because air is blown across the pellets for 

convective cooling. This does not take place in the other Group 2 material handling sources; 

therefore, pellet coolers are analyzed by a separate model source. 

Straight grate furnaces and grate/kiln furnaces were selected as model sources for PM, NOx and 

SO2 emissions in Group 3. 

Source category emissions data from the 2001 emissions inventory are summarized in Table 5-4. 

Note that the percent of the group total emissions to the facility-wide emissions takes into 

account emissions from all taconite plant and mine sources listed in the emission inventory. 

Table 5-4 

2001 PM10 Emissions (tpy) Breakdown for Group 2 and 3 Source Categories 

2001 PM10 Emissions (tpy) 

Group 2 Secondary Source 

Category Description 

No. of 

Sources 

in EI Avg Max Min Total 

Percent of 

Group to 

Facility-wide 

PM10 

Emissions 

2.01 Crushing 78 3.4 6.9 0.0 267.2 2.5% 

2.02 Material Handling – Ore 110 9.3 59.1 0.1 1,027.0 9.6% 

2.03 Material Handling – Additive 40 2.0 28.7 0.0 80.1 0.8% 

2.04 Material Handling – Coal 16 0.1 2.0 0.0 2.0 0.0% 

2.05 Straight Grate (Grate) 0 NA NA NA NA 

2.06 Straight Grate (Pellet Discharge) 4 16.2 20.6 5.3 64.7 0.6% 

2.07 Grate-Kiln (Grate) 12 74.3 125.6 7.3 892.0 8.4% 

2.08 Grate-Kiln (Cooler) 4 48.7 129.5 2.9 194.7 1.8% 

2.09 Grate-Kiln (Pellet Discharge) 0 NA NA NA NA 

2.10 Material Handling - Pellets 57 13.0 269.1 0.2 738.4 6.9% 

Group 2 Total PM10 Emissions 3,266 30.7% 

 

Group 3 Secondary Source 

Category Description 

3.01 Straight Grate (Induration) 2 152 157 147 304 2.9% 

3.02 Grate-Kiln (Induration) 9 434 1,299 81 3,906 36.7% 

Group 3 Total PM10 Emissions 4,210 39.6% 

 

Group 2 and 3 Total PM10 

Emissions 7,476 70.3% 
43

Table 5-5 

2001 SO2 and NOx Emissions (tpy) Breakdown by Type of Induration Furnace 

Pollutant 

Straight 

Grate Grate-Kiln 

Induration 

Furnace 

Total 

Facilitywide 

Emissions 

Percent of Induration 

Furnace to 

Facility-wide 

Emissions 

NOx 3,737 18,186 21,923 27,636 79.3% 

SO2 281 5,689 5,970 8,129 73.4% 

Table 5-5 shows that the PM10, SO2, and NOx emissions from group 2 and 3 sources constitute 

over 70 percent of total actual 2001 facility-wide emissions. 
44

6 Identification of Available Control Technologies 

This section describes each potentially available control technology evaluated for the taconite 

industry model sources defined in Section 5.8.3. The technologies are grouped by the pollutant 

that they control (i.e., NOx, SO2, or PM). 

Determining technical feasibility of a control technology for a new source (e.g., determining best 

available control technology at a new induration furnace) will be different than determining 

technical feasibility for a retrofit at an existing source (e.g., determining best available retrofit 

technology at an existing induration furnace). In this section, Barr determines the technical 

feasibility of each control technology for a taconite plant emission unit as if that unit could be 

designed or re-designed to meet the control device physical and operating parameters. In 

Section 7, Barr performs an additional technical feasibility evaluation of each remaining control 

technology as a retrofit to an existing emission unit, consistent with BART. 

For mining operations, control technology options for PM10 include dust suppression and 

enclosure. For crushing and concentrating operations, control technology options for PM10

include enclosure, dust suppression system, scrubber (low/high efficiency), fabric filter, and 

electrostatic precipitator. For pelletizing operations, control technology options for PM10 include 

multiclone, baghouse, scrubber, and electrostatic precipitator/wet electrostatic precipitator; 

control technology options for SO2 include scrubber (low/high efficiency) and wet electrostatic 

precipitator; control technology options for NOx include combustion control, low- NOx burner, 

selective catalytic reduction, and selective non-catalytic reduction. For this report, two types of 

low-NOx burners are evaluated, staged fuel low-NOx burners and induced flue gas recirculation 

burners (IFGR or ultra-low NOx). External flue gas recirculation is a common technique for 

controlling NOx emissions, so it is added to the list of NOx control technologies for review. 

As part of the BART screening evaluation, a literature review was conducted to identify potential 

new control equipment options that were not included in the list of control equipment from the 

draft report submitted on May 12, 2003. The results of the literature search are summarized in 

spreadsheet format in Attachment H. 

6.1 NOx Emission Control Options 

Nine different control technologies are evaluated for NOx emissions from induration furnace 

waste gases. Of these, three have been determined technically infeasible for induration furnaces: 

(1) coal addition to green taconite pellets, (2) non-selective catalytic reduction, and (3) lowtemperature oxidation. 

Section 6.1.10 considers site-specific operational factors that may reduce NOx emissions without 

employing control technologies. 

6.1.1 External Flue Gas Recirculation 

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

temperatures. In an external flue gas recirculation system, flue gas is collected from the heater or 
45

stack and returned to the burner via a duct and blower. The flue gas is mixed with the 

combustion air and this mixture is introduced into the burner. The addition of flue gas reduces 

the oxygen content of the “combustion air” (air + flue gas) in the burner. The lower oxygen level 

in the combustion zone reduces flame temperatures; which in turn reduces NOx emissions. 

The normal NOx control efficiency range for EFGR is 30% to 50%. 

6.1.2 Low-NOx Burners 

Low-NOx burner (LNB) technology utilizes advanced burner design to reduce NOx formation 

through the restriction of oxygen, flame temperature, and/or residence time. LNB is a staged 

combustion process that is designed to split fuel combustion into two zones, primary combustion 

and secondary combustion. This analysis utilizes the staged fuel design in the cost analysis 

because lower emission rates can be achieved with staged fuel burner than with a staged air 

burner. 

In the primary combustion zone of a staged fuel burner, NOx formation is limited by a rich (high 

fuel) condition. Oxygen levels and flame temperatures are low; this results in less NOx 

formation. In the secondary combustion zone, incomplete combustion products formed in the 

primary zone act as reducing agents. In a reducing atmosphere, nitrogen compounds are 

preferentially converted to molecular nitrogen (N2) over nitric oxide (NO). 

The estimated NOx control efficiency for Low NOx burners in high temperature applications is 

25%. 

6.1.3 Induced Flue Gas Recirculation Burners 

Induced flue gas recirculation burners, also called ultra low-NOx burners, combine the benefits 

of flue gas recirculation and low-NOx burner control technologies. The burner is designed to 

draw flue gas to dilute the fuel in order to reduce the flame temperature. These burners also 

utilize staged fuel combustion to further reduce flame temperature. 

The estimated NOx control efficiency for IFGR burners in high temperature applications is 50%. 

6.1.4 Selective Non-Catalytic Reduction 

In the selective non-catalytic reduction (SNCR) process, urea or ammonia-based chemicals are 

injected into the flue gas stream to convert NO to N2 and water. Without the participation of a 

catalyst, the reaction requires a high temperature range to obtain activation energy. The relevant 

reactions are as follows: 

NO + NH3 + 1/4 O2 → N2 + 3/2 H2O 

NH3 + 1/4 O2 → NO + 3/2 H2O 

The optimum operating temperature for SNCR is 1,600°F to 2,000°F. Under these conditions 

reaction (1) dominates, and a significant reduction in NOx occurs. At temperatures above 

2,000°F reaction (2) begins to dominate and NOx control efficiency decreases rapidly. 
46

The normal NOx control efficiency range for SNCR is 50% to 70%. 

6.1.5 Selective Catalytic Reduction 

Selective catalytic reduction (SCR) is a post-combustion NOx control technology in which 

ammonia (NH3) is injected into the flue gas stream in the presence of a catalyst. NOx is removed 

through the following chemical reaction: 

4 NO + 4 NH3 + O2 → 4 N2 + 6 H2O 

2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O 

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

required for NOx decomposition. SCR requires a temperature range of 500°F – 800°F for a 

normal catalyst. The optimum operating temperature range is 700°F to 750°F. 

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. 

The normal NOx control efficiency range for SCR is 70% to 90%. 

6.1.6 Ported Kilns 

Ported kilns are rotary kilns that have air ports installed at specified points along the length of the 

kiln. 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 extracts 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 prevents carry over of the oxidation reaction into the pellet coolers. 

Minntac has worked with Metso Minerals to install two ported kilns. Metso’s product 

specifications for ported kilns suggest a 5% reduction in energy use. Minntac has confirmed that 

they have achieved at least a 5% reduction in fuel consumption. They also have seen a slight 

reduction in NOx emissions over and above the reduction in energy use. This is most likely the 

result of lower temperatures in the kiln from air injection. 

6.1.7 Coal Addition to Pellets with Low Excess Air in the Induration 

Furnace 

John Engesser of the Minnesota Department of Natural Resources (MDNR) has been performing 

research on the impact of coal addition to green taconite pellets as a possible way to reduce NOx 

emissions from pellet induration. Coal addition of 0.6% was shown not to adversely affect pellet 

quality. Pellet quality began to degrade when coal addition was increased to 1%. 
47

The MDNR did not find a significant reduction in NOx emissions from the coal addition under 

normal induration conditions in their test furnaces at 300% excess air. The MDNR’s data 

suggests an average reduction in NOx emission of 10 % when the excess air levels in the test 

furnaces was reduced to 25 % to 75%. The test furnaces operate on a batch basis, and much of 

the energy consumption is due to heating the furnace up to test conditions. The MDNR 

postulates that a 75% reduction can be achieved if this practice is carried out in a continuously 

operated kiln. 

The project is still in the research phase and more research is needed. It is not commercially 

available at this time. Coal addition to green taconite pellets is not considered further in the 

BART screening evaluation. 

6.1.8 Non-Selective Catalytic Reduction 

A non-selective catalytic reduction (NSCR) system is a post combustion add-on exhaust gas 

treatment system. It is often referred to as “three-way conversion” catalyst since it reduces NOx, 

unburdened hydrocarbons (UBH), and CO simultaneously. NOx and CO react in the presence of 

NSCR catalyst to form nitrogen (N2) and carbon dioxide (CO2). In order to operate properly, the 

combustion process must be near-stoichiometric conditions. SCONOxTM is a commercially 

available example of an NSCR system. SCONOxTM employs a single catalyst that 

simultaneously oxidizes CO to CO2 and NO to NO2. NO2 formed by the oxidation of NO is 

subsequently absorbed onto the catalyst surface through the use of a potassium carbonate 

absorber coating. CO2 produced by these reactions is released to the atmosphere. The potassium 

carbonate catalyst coating reacts with NO2 to form potassium nitrites and nitrates. Prior to 

saturation of the potassium carbonate coating, the catalyst must be regenerated. 

SCONOxTM is typically employed in clean gas services such as natural gas fired turbines. The 

SCONOxTM catalyst is very sensitive to contaminants in the waste gas and would not be viable in 

induration waste gas service. NOx control efficiency for NSCR is approximately 90% in clean 

combustion applications. 

When Barr evaluated SCONOxTM for a potential new taconite plant in 2001, Goal Line 

Technologies indicated that SCONOxTM is technologically infeasible in this application. 

NSCR is not considered further in the BART screening evaluation. 

6.1.9 Low Temperature Oxidation 

Low temperature oxidation (LTO) utilizes ozone as a medium to oxidize various pollutants 

including NOx. In the system, NOx in the flue gas is oxidized by means of ozone to form 

nitrogen trioxide or nitrogen pentoxide. These compounds react with water vapor to form nitric 

acid. The nitric acid vapor is then absorbed as dilute nitric acid and is neutralized by the sodium 

hydroxide in the scrubbing solution to form sodium nitrate. The sodium nitrate is separated and 

discharged to the wastewater system. LTO is typically employed at locations where the nitrate 

byproduct and be used or recycled. 
48

BOC Gases’ Lo-TOx is an example of a commercially available version of an LTO system that 

was evaluated by Barr in 2001 for a potential new taconite plant. Lo-TOx technology uses ozone 

to oxidize NO to NO2 and NO2 to N2O5 in reactor. The N2O5 is converted to HNO3 in a scrubber, 

and is removed with caustic. The reactions are as follows: 

O3 + NO → O2 + NO2 

NO2 + O3 → 2 N2O5 

N2O5 + H2O → 2 HNO3 

NaOH + HNO3 → NaNO3 + H2O 

The normal NOx control efficiency range for Lo-TOx is 80% to 95%. 

Lo-TOx would require a minimum of two process columns, a reactor for NOx oxidation, and a 

scrubber for nitrate removal. In addition, an ozone generator with a supply of liquefied oxygen 

would be required. As a result of equipment requirements, this is a rather expensive control 

technology. Nitrates are produced as a byproduct of this control technology. At a taconite plant, 

there is no place to utilize these nitrates, so this wastewater would be routed to the tailings basin. 

Nitrates in the tailings basin would pose a threat to ground and surface water. Tables I-15 and I16 in Attachment I contain cost estimates for application of Lo-TOx technology for the model 

source grate/kiln induration furnace. The estimated control cost is $6,310/ton for the 175 ppm 

NOx case and $12,500/ton for the 50 ppm NOx case. Based on the NOx emission rate19, the 

control cost for a straight grate induration would be similar to the 50 ppm NOx grate/kiln 

estimate. The estimates are based on bid data from the 2001 Taconite BACT study. 

Barr contacted Tri-Mer Corporation, the manufacturer of the Tri-NOx® LTO system, to 

determine the applicability of LTO at a potential new taconite plant in 2001. The vendor stated 

that Tri-NOx® LTO system is not commercially available for use on a taconite pellet induration 

furnace. Tri-Mer stated that the magnitude of the air streams from an induration furnace is too 

large for the chemistry used in the Tri-NOx® system to reduce NOx effectively. 

LTO is not considered further in the BART screening evaluation. 

6.1.10 Site-specific Measures 

Site-specific measures may also be employed to reduce NOx emissions. Under this option, 

taconite plant operators would employ the best operating practices identified for NOx reduction 

using existing equipment. 

One option is to evaluate NOx emission rates under various operating conditions to identity 

which conditions lead to the lowest NOx emission rates. NOx emission rates could be 

determined by stack testing, continuous emission monitors, or predictive emission monitors. 

 

19 Equipment costs in the Lo-TOx vendor quotes were directly proportional to the NOx removal rate; waste gas flow 

rates did not have a significant impact on equipment costs.. 
49

If a taconite plant is capable of using more than one fuel type, another option is to evaluate the 

impact of fuels on NOx emission rates. Stack test data from one facility shows a 60% reduction 

in NOx emissions when using coal instead of natural gas. A 30% reduction occurred when firing 

16% wood waste, and a 50% reduction when firing 28% wood waste. If this option is employed, 

increases in SO2 and PM emissions should be compared to the NOx reductions to identify the 

best net reduction in visibility impairing pollutants. 

6.2 SO2 Emission Control Options 

Four control technologies are evaluated for SO2 emissions from induration furnace waste gases. 

Of these, two have been determined technically infeasible for induration furnaces: 1) dry 

scrubbing lime/limestone injection, and 2) spray dryer absorption. 

6.2.1 Wet Walled Electrostatic Precipitator 

A wet walled electrostatic precipitator (WWESP) operates on the same collection principles as a 

dry ESP (see Section 6.3.5), and uses a water spray to remove particulate matter from the 

collection plates. For SO2 removal, caustic is added to the water spray system, allowing the 

WWESP spray system to function as an SO2 absorber. 

The SO2 control efficiency for a WWESP is approximately 80%. 

6.2.2 Wet Scrubbing / Flue-Gas Desulfurization 

Wet scrubbing techniques are used to control both particulate and SO2 emissions. As discussed 

in Section 6.3.8, particulate scrubbers are wet scrubbers that remove particles from waste gas by 

capturing the particles in liquid droplets (usually water) and separating the droplets from the gas 

stream. Wet scrubbing processes used to control SO2 are generally termed flue-gas 

desulfurization (FGD) processes. FGD utilizes gas absorption technology, the selective transfer 

of materials from a gas to a contacting liquid, to remove SO2 in the waste gas. Caustic, crushed 

limestone, or lime are used as scrubbing agents. The BART screening evaluation assumes that 

caustic (sodium hydroxide solution) is the scrubbing agent. The SO2 removal reactions are as 

follows: 

Na+ + OH- + SO2 + → Na2SO3 

2Na+ + 2OH- + SO2 + → Na2SO3 + H2O 

Limestone scrubbing introduces limestone slurry with the flue gas in a spray tower. The sulfur 

dioxide is absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. 

The overall reactions are shown in the following equations: 

CaCO3 + SO2 → CaSO3

• 1/2 H2O + CO2 

CaSO3 

•

1/2 H2O + 3H2O + O2 → 2 CaSO4

•

2 H2O 

Lime scrubbing is similar to limestone scrubbing in equipment and process flow, except that 

lime is a more reactive reagent than limestone. The reactions for lime scrubbing are as follows:
50

Ca(OH)2 +SO2 → CaSO3• 1/2 H2O + 1/2 H2O 

Ca(OH)2 + SO2 + 1/2 O2 + H2O → CaSO4•2 H2O 

Caustic scrubbing produces a liquid waste, and minimal equipment is needed. If lime or 

limestone is used as the reagent for SO2 removal, additional equipment will be needed for 

preparing the lime/limestone slurry and collecting and concentrating the resultant sludge. 

Calcium sulfite sludge is watery; it is typically stabilized with fly ash for land filling. The 

calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air injection 

blower is needed to supply the oxygen for the second reaction to occur. 

The normal SO2 control efficiency range for SO2 scrubbers is 80% to 90% for low efficiency 

scrubbers and 90% to 95% for high efficiency scrubbers 

6.2.3 Dry Scrubbing Lime/Limestone Injection 

Lime/limestone injection is a post-combustion SO2 control technology in which pulverized lime 

or limestone is directly injected into the duct upstream of the fabric filter. Dry sorption of SO2

onto the lime or limestone particle occurs and the solid particles are collected with a fabric filter. 

Further SO2 removal occurs as the flue gas flows through the filter cake on the bags. The normal 

SO2 control efficiency range for dry SO2 scrubbers is 70% to 90%. 

Induration waste gas streams are high in water content and are exhausted at or near their dew 

points. Gases leaving the induration furnace are typically in the 100 °F to 150 °F range as 

compared to a utility boiler exhaust that operates at 350 °F or higher. Under induration furnace 

waste gas conditions, the baghouse filter cake could become saturated with moisture and plug 

both the filters and the dust removal system. In facilities where wet scrubbers are used, water in 

the scrubber exhaust would compound this problem. Therefore, this control system is not 

considered technically feasible in induration waste gas service and is not considered further in 

the BART screening evaluation. 

6.2.4 Spray Dryer Absorption 

Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO2 is 

absorbed by the slurry, forming CaSO3/CaSO4. The liquid-to-gas ratio is such that the water 

evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with 

the gas and collected with a fabric filter. When used to specifically control SO2, the term flue-gas 

desulfurization (FGD) may also be used. 

As with the dry scrubbing system in Section 6.2.3, under induration furnace waste gas 

conditions, the baghouse filter cake could become saturated with moisture and plug both the 

filters and the dust removal system. In addition, the lime slurry would not dry properly and it 

would plug up the dust collection system. Therefore, spray dryer absorption is not technically 

feasible in this application and is not considered further in the BART screening evaluation. 
51

6.3 PM Emission Control Options 

Eight control technologies are evaluated for PM emissions in induration waste gas, induration 

pellet cooler exhaust, enclosed material handling sources, or fugitive sources. All of these control 

technologies are deemed technically feasible for a new unit. 

6.3.1 Best Management Practices 

Best management practices are preventative measures that minimize the release of particulate 

matter into the environment. Best management practices may include the proper design and 

maintenance of equipment, good housekeeping, and good operating practices such as using 

telescopic chutes for loading and unloading procedures, limiting drop heights, covering truck 

beds, and orienting storage piles perpendicularly to prevailing winds to reduce the exposed 

surface. 

The PM control efficiency range for best management practices varies depending upon the 

application. 

6.3.2 Wet Suppression 

Wet suppression is a potential control method for particulate matter emitted from material 

handling and other fugitive sources. Wet suppression systems apply either water or water 

containing a chemical surfactant or foaming agent to the surface of the particulate generating 

material. The chemical surfactant or foaming agent agglomerates and binds the particulates to the 

aggregate surface thus eliminating or reducing its emission potential. 

The normal PM control efficiency range for wet suppression is 50% to 75%. 

6.3.3 Enclosure 

An enclosure is a potential control method for particulate emissions from material handling 

sources. Enclosures, either partial or complete, surround the source as much as possible without 

interfering with the process operations. Enclosures prevent particulate matter from becoming 

airborne as a result of disturbance created by ambient winds or by mechanical entrainment 

resulting from the operation of the source causing the emissions. 

The normal PM control efficiency range for an enclosure is 50% to 100%. 

6.3.4 Cyclone Separator 

Cyclone separators, or multiclones, are a potential control method for particulate emissions in 

induration waste gas, induration pellet cooler exhaust, or enclosed material handling sources. 

Cyclone separators are designed to remove particles by causing the exhaust gas stream to flow in 

a spiral pattern inside of a tube. Owing to centrifugal forces, the larger particles slide down the 

wall and drop to the bottom of the cyclone where they are removed. The cleaned gas flows out of 

the top the cyclone. 
52

There are two principal types of cyclones: tangential entry and axial entry. In tangential entry 

cyclones, the exhaust gas enters an opening located on the tangent at the top of the unit. In axial 

flow cyclones, the exhaust gases enter at the middle of one end of a cylinder and flows through 

vanes that cause the gas to spin. A peripheral stream removes collected particles, while the 

cleaned gas exits at the center of the opposite end of the cylinder. 

A typical emission control rate for a multiclone is 50% to 80%. The control efficiency for 

cyclone separators is less for small particles than larger particles. Particle size distribution data is 

necessary to properly determine the control efficiency for a specific application. 

6.3.5 Electrostatic Precipitator 

An electrostatic precipitator (ESP) is a potential control method for particulates in induration 

waste gas, induration pellet cooler exhaust, or material handling sources that are enclosed. An 

electrostatic precipitator applies electrical forces to separate suspended particles from the flue 

gas stream. The suspended particles are given an electrical charge by passing through a highvoltage 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. 

The normal PM control efficiency range for an ESP is 98% to 99+%. 

6.3.6 Wet Walled Electrostatic Precipitator 

A wet walled electrostatic precipitator (WWESP) is a potential control method for particulates in 

induration waste gas, induration pellet cooler exhaust, or material handling sources that are 

enclosed. A WWESP operates on the same collection principles as a dry ESP, and uses a water 

spray to remove particulate matter from the collection plates. 

The normal PM control efficiency range for a WWESP is 98% to 99+%. 

6.3.7 Fabric Filter 

A fabric filter, or baghouse, is a potential control method for particulates in induration pellet 

cooler exhaust, or material handling sources that are enclosed. Moisture levels in the induration 

waste gas are too high for fabric filters. A fabric filter, or baghouse, consists of a number of 

fabric bags placed in parallel inside of an enclosure. Particulate matter is collected on the surface 

of the bags as the gas stream passes through them. The particulate is periodically removed from 

the bags and collected in hoppers located beneath the bags. A number of methods are employed 

to facilitate the removal of particulate from the bags, including shaking, reverse air flow, and 

pulse air flow. 

The normal PM control efficiency range for a fabric filter is 98% to 99+%. 
53

6.3.8 Particulate Scrubbers 

A scrubber is a potential control method for particulates in induration waste gas, induration pellet 

cooler exhaust, or material handling sources that are enclosed. Particulate scrubbers, also termed 

wet scrubbers, remove particles from waste gas by capturing the particles in liquid droplets 

(usually water) and separating the droplets from the gas stream. The droplets transport the 

particulate out of the gas stream. 

Scrubbers capture the particulates through the following mechanisms: 

1. Impaction of the particle directly into a target droplet 

2. Interception of the particle by a target droplet as the particle comes near the droplet 

3. Diffusion of the particle through the gas surrounding the target droplet until the particle is 

close enough to be captured 

Scrubbers are generally classified according to the liquid contacting mechanism used. The most 

common scrubber designs are spray-chamber scrubbers, cyclone spray chambers, orifice and 

wet-impingement scrubbers, and venturi and venturi jet scrubbers. 

The normal PM control efficiency range for a scrubber is 90% to 95% for a low efficiency 

scrubber and 95% to 99+% for a high efficiency scrubber. 
54

7 Application of BART Screening to Model Taconite Sources 

The first four of the five BART evaluation steps described in Section 4.2.4 are completed in this 

section on an industry-wide screening level. The fifth step, selecting BART, will ultimately be 

performed on a case-by-case evaluation by the facility and MPCA. 

The analysis of potential BART control technologies must take into account: 

• The available retrofit control options, 

• Any pollution control equipment in use at the source, 

• The costs of compliance with control options, 

• The remaining useful life of the facility, and 

• The energy and non-air quality environmental impacts of control options. 

The BART screening study uses model sources, which are similar to some actual emission 

sources at taconite plants to evaluate potential control costs for step 4. Each taconite plant is 

different, and site-specific issues must be considered in the BART analysis. An actual BART 

analysis must be conducted for individual taconite facilities so that facility-specific factors are 

taken into account. Please see Section 7.1.2 for a list of issues for consideration in the sitespecific analysis. The screening BART analysis used the following primary information sources. 

A literature search for this study is contained in Attachment H of this report. Cost information 

was developed from the following sources: 

• Emission control costs are estimated using the capital and operating cost estimate factors 

in the EPA Air Pollution Control Cost Manual , sixth edition (EPA/452/B-02-001). 

• Control equipment costs are estimated from vendor quotations from a 2001 BACT study 

by Barr for a potential new taconite plant. These estimates are adjusted for inflation using 

the Vatavuk Air Pollution Control Cost Indexes. 

• Information gaps are addressed by collecting additional cost data from control equipment 

manufacturers. 

• Gas and electric costs are based on the U.S. Department of Energy's 2002 data for 

industrial sources (http://www.eia.doe.gov). 

• Wastewater treatment costs are obtained from the EPA Air Pollution Control Cost 

Manual. The EPA-estimated treatment costs are used as a placeholder for site-specific 

values. Please see Section 7.1.2 with regard to site-specific factors that could 

significantly affect wastewater treatment costs. 
55

The BART screening evaluation in this report does not make recommendations for the selection 

of BART in step 5. Final selection of BART will be done on a facility-by-facility basis. This will 

allow consideration of site-specific issues in control equipment construction costs, pollution 

control efficiency and compliance costs. 

7.1 General Control Technology Review Issues 

This section outlines important issues that must be taken into account when performing a caseby-case BART evaluation. 

7.1.1 Emission Controls vs. Impact on Visibility 

In accordance with 40 CFR 51.308(e)(1)(ii)(A) and (B), a BART determination must be based on 

the following two analyses: 

“(A) An analysis of the best system of continuous emission control technology available and 

associated emission reductions achievable for each BART-eligible source ...; and 

(B) An analysis of the degree of visibility improvement that would be achieved in each 

mandatory Class I Federal area as a result of the emission reductions achievable from all 

sources subject to BART located within the region that contributes to visibility impairment in 

the Class I area, based on the analysis conducted under paragraph (e)(1)(ii)(A) of this 

section.” 

The emission control costs reported in this section for the model sources are in units of dollars 

per ton of pollutant removed. However, each pollutant has a different impact on visibility. 

At a July 8, 2003 meeting on Regional Haze, Mr. Gordon Andersson at MPCA indicated that 

sulfates comprise the majority of mass of haze generating emissions. Nitrates are also a major 

contributor during winter months. A study on visibility impairment by Colorado State University 

found that sulfates contribute 54 % of the visibility impairment and nitrates contribute 17 % of 

the visibility impairment in the Voyageurs National Park and BWCAW. 

7.1.2 Site-specific Factors that Affect Control Costs 

Although the model sources have been developed to provide a general indication of the technical 

and economic feasibility of each control technology, a unit-specific BART evaluation must still 

be performed. A case-by-case evaluation should consider these steps. 

• Determine the technical feasibility of listed control equipment for each source subject to 

BART. Check the technical feasibility analysis to see if analysis is consistent with sitespecific conditions. Eliminate all technologies that are infeasible. 

• Conduct a control cost analysis on the remaining technologies per the listed control 

technology rankings. It is recommended that site-specific vendor quotes be obtained to 

get accurate cost analysis results. If there are a significant number of similar sources, 

select a typical-sized source to minimize the amount of work needed to perform the cost 

analysis. Use the appropriate model source cost analysis in the attachments to this report 
56

as guidance for the cost analysis. Review the list of factors that affect site-specific retrofit 

costs. Identify those factors for which costs will affect control equipment installation at 

the site and include them in the cost analysis. Check the utility costs listed in the 

attachments to this report, and make the appropriate adjustments in the cost calculations. 

• Compare the calculated control costs to the results of the economic affordability analysis 

to determine which controls are economically feasible and select the appropriate controls 

as BART. Conduct a site-specific economic analysis of control cost affordability. 

Site-specific factors can significantly impact the installed costs of pollution control equipment. 

This is especially true at retrofits of existing equipment, which is the case with BART-eligible 

sources. Site-specific factors that can impact control costs include: 

• Site preparation work due to removal of existing equipment or modification of existing 

buildings and structures. 

• Site access for equipment delivery and erection. Existing buildings and structures may 

limit access to the construction site by cranes and other construction equipment. 

• Additional engineering costs to address piping and duct work tie-ins to existing 

equipment and structural issues caused by installing new equipment that was not planned 

for in the original equipment design. Process Safety Management Hazardous Operation 

(Haz-Op) review requirements and resultant safety system designs could also add to 

engineering costs. 

• Additional piping and insulation costs to fit new piping and ductwork within existing 

pipe racks and equipment support structures. 

• Auxiliary equipment that may be needed to accommodate the new control system e.g. 

blowers, heat exchangers, duct burners, or bypass stacks. 

• Lost production due to process equipment down time while the new equipment is being 

installed. This generally occurs when piping and duct work are tied in to existing 

equipment. 

• Taconite plants are located in relatively remote locations; freight costs will be higher than 

standard estimating factors. 

• Taconite plants are large facilities. Installation of control equipment will likely require 

on-site fabrication, which increases construction costs. 

• Site-specific wastewater treatment costs should be carefully evaluated. Different iron ore 

and raw materials used in pellet production affect the type of constituents in induration 

emissions (e.g. chlorides, fluorides, sulfates and various metals). When these materials 

are captured by wet scrubbing systems, they will likely affect wastewater quality, and the 

impact of scrubber blowdown on wastewater/tailings management systems should be 

considered. Compliance with water quality standards also needs to be considered. 
57

Taconite plants are located in different watersheds, which have differing water quality 

issues. Site-specific water quality issues could significantly affect water treatment costs. 

Currently, no taconite plant has water treatment facilities for scrubber blowdown. A caseby-case study of wastewater treatment requirements and costs is needed for the economic 

analysis of pollution control costs. 

7.2 Model Source Parameters 

The BART screening evaluation uses model sources to develop cost estimates for pollution 

control equipment. The model source parameters are listed in Table 7-1. 

The model source parameters were set at the mid-point of the range of equipment in Minnesota’s 

taconite plants. These parameters are determined using 2001 emission inventory data, taconite 

performance test data from MPCA’s report, “U.S Taconite Iron Ore Industry” by Hongming 

Jiang, and Barr’s taconite plant performance testing experience. 
58

Table 7-1 

Taconite Model Source Characteristics for BART Screening Evaluation

Stack Exhaust Parameters 

Source Type Vent Type 

Normal Flow

(dscfm) 

Normal Flow

(acfm) 

Design 

Flow [1] 

(acfm) 

Temperature 

(F) 

Moisture 

(%) 

SO2 

Conc. (ppm) 

Straight Grate Induration 

Waste Gas 

150,000 188,865 207,751 135 12% 5 

Grate/Kiln Induration 

Waste Gas 

300,000 377,730 415,503 135 12% 20 (low) 

and 130 (high) [2

Pellet Cooler Pellet Cooler 

Exhaust 

100,000 239,425 263,368 800 2% NA 

Ore Material Handling 

Conveyor Drop 7000 7,143 7,857 77 2% NA Conveyor Drop Height 

10 ft 

Conveyor Width 5 ft Throughput 5.00E+06 tpy 

ore 

[1] Design flow is estimated at 10% greater than normal flow. Design flow is used to estimate equipment costs; normal flow operating costs. [2] A “low” and a “high” case for SO2 and NOx stack concentration are used in the screening evaluation to account for differe

controls at the taconite plants. [3] PM concentration of 0.05 gr/dscf is based on emissions using AP-42 factors and a flow rate of 7000 dscfm. It is a more r

allowable grain loading standard of 0.3 gr/dscf in Minnesota rules. 
59

7.3 Model Induration Furnace NOx Control Technology Review 

Thermal NOx from fuel combustion is the primary source of emissions from induration. Fuelbased NOx emissions are also present where fuel oil and solid fuels are used. However, test data 

from one taconite facility showed a reduction in NOx when firing solid fuels. 

As shown in Section 8, no specific regulatory limits for NOx emissions exist for taconite 

induration furnaces. 

7.3.1 BART Step 1: Identify All Available Retrofit Control Technologies 

Control technologies available for NOx are as follows: 

• External Flue Gas Recirculation (EFGR) 

• Low-NOx Burners (Staged Fuel) 

• Internal FGR (Ultra Low NOx Burners) 

• Selective Non Catalytic Reduction (SNCR) 

• Selective Catalytic Reduction (SCR) 

• Ported Kilns 

See Section 6.1 for additional information on these control technologies and additional 

technologies identified in the literature search. 

7.3.2 BART Step 2: Eliminate Technically Infeasible Options 

A summary of the technical feasibility analysis is listed in Table 7-2. Details of the analysis for 

each control technology follow the summary table. 
60

Table 7-2 

Summary of Technical Feasibility for Induration NOx Emissions 

Control Technology 

Feasibility 

Determination

Issues That Affect 

Control Technology Feasibility 

1. EFGR Infeasible Induration requires high oxygen levels in the furnace to 

oxidize pellets. EFGR would reduce oxygen levels below 

required levels. 

2. Low-NOx Burners Feasible only 

at pre-heat 

section 

Feasible only at the induration furnace pellet pre-heat 

section. Infeasible at the induration furnace due to 

excessive temperature and oxygen level. 

3. IFGR Burners Feasible only 

at pre-heat 

section 

Feasible only at the induration furnace pellet pre-heat 

section. Infeasible at the induration section of the furnace 

due to excessive temperature and oxygen level. 

4. SNCR Infeasible No points to inject reagent at the proper temperature 

and/or potential ammonium sulfate plugging problems in 

the preheat section of the induration furnace. 

5. SCR Feasible only if 

exhaust gas is 

re-heated 

Installation directly in the induration process is likely 

infeasible, since there is not a location within the system 

at a proper operating temperature. Installation as add on 

control device is feasible if exhaust gases are re-heated 

to the SCR operating temperature. 

6. Ported Kiln Feasible only 

at grate/kiln 

systems 

Two ported grate/kilns are currently in operation. 

1. EFGR - Infeasible 

It is not a viable option to re-route flue gas to the combustion zone of the induration process. 

External flue gas recirculation would lower the temperature range and oxygen levels needed for 

pellet induration. Pellets must be held at an optimum temperature (2400 to 2450 °F), in the 

presence of excess oxygen, for a sufficient time to allow oxidation to reach the pellet center and 

allow realignment of the molecules to form stronger microstructures in the pellet. 

2 and 3. Low-NOx and IFGR Burners – Feasible only in pre-heat section 

Operating conditions in the induration furnace are inconsistent with the NOx control mechanisms 

used in these burners. Low-NOx and IFGR burners reduce NOx formation by restricting flame 

temperature under low oxygen levels. In the induration furnace, pellets must be heated to, and 

maintained at, a temperature of 2400 to 2450°F, to produce a completely oxidized, high strength 

and abrasion resistant pellet. High flame temperatures are needed for the radiant heat transfer 

needed to maintain these temperatures. In addition, high levels of oxygen are needed to achieve 

proper oxidation. Typical operating conditions are at 15% to 17% oxygen. Induration furnaces 

are designed to use pre-heated combustion air to conserve energy. Air preheat restricts that 

ability of low NOx and IFGR burners to reduce NOx formation. 

Figure 7-1 shows the equilibrium concentrations of NO at different temperatures. The tick mark 

for induration furnaces on this curve shows that there is a high potential for NOx formation. . 

Figure 7-2 on the following page shows NOx formation rates at several temperature ranges. Each 

set of curves shows the concentrations of NO formed in 2 to 3 seconds at the listed temperature 

and oxygen concentrations. Induration furnace conditions are similar to the 1,000 ppm NOx 
61

curve. This curve shows how conducive the induration furnace operating conditions are to NOx 

formation. Under these conditions low-NOx and IFGR burners would be ineffective. 

Figure 7-1. Equilibrium NOx Concentrations at Various Temperatures for a Typical 

Induration Furnace Waste Gas 

Equilibrium NO (ppm) for Waste Gas: 16.9% O2 + 80.1% N2

0

1000

2000

3000

4000

5000

6000

0 500 1000 1500 2000 2500 3000

Temperature, Degree F

Source: Minnesota Pollution Control Agency; Hongming Jiang 
62

Figure 7-2. Impact of Temperature on NOx Formation 

Source: “Alternative Control Techniques Document—NOx Emissions from Process Heaters (Revised),” US EPA, 

EPA-453/R-93-034, September 1993. 

Temperatures in the pellet pre-heat section are typically below 2,000 °F. At this temperature 

range, the use of low-NOx and IFGR burners is technically feasible. However, the NOx control 

efficiency of burners installed at these conditions is limited due to the high temperature of the 

combustion air and the high levels of oxygen present for pellet oxidation. Site-specific product 

quality concerns may limit the feasibility of this option. For example, one facility cannot make 

fully fluxed pellets if there is a reduction in temperature in the pre-heat zone. This could preclude 

use of low NOx burners due to the lower flame temperatures in low NOx burners. 

Low NOx and IFGR Burners typically have longer flame patterns than standard burners. The 

impact of longer flames should be evaluated when considering installation of these burners. 

No test data are available to substantiate the feasibility of Low NOx burners. Low NOx burners 

have only been installed at one straight grate facility, but no performance tests were conducted 

before or after installation of the low NOx burners; so, it cannot be determined if these burners 

actually reduce NOx emissions. Low NOx burners have not been installed at a grate/kiln facility. 
63

4. SNCR – Infeasible 

The SNCR reagents must be injected into the furnace at 1,600 °F to 2000 °F. The operating 

temperatures in induration furnaces exceed this temperature window. An induration furnace is 

designed such that the flue gas dries and pre-heats the taconite pellets. As the induration flue gas 

heats the taconite pellets, its temperature drops below the SNCR operating temperature range. 

Therefore, it may be difficult to locate an appropriate temperature window for SNCR in an 

existing induration flue gas duct system. 

A second issue with SNCR is the potential for plugging in the induration furnace pre-heat section 

due to the presence of ammonium sulfate salts. Sulfur oxides present in the induration waste gas 

can react with excess ammonia from the SNCR process to form ammonium salts. These 

materials are very sticky and cause plugging problems if the gas drops below the dew point of 

350° F. Temperatures below 350° F will occur in the preheat section; therefore; it is likely that 

the ammonium salts will deposit on the cool surfaces present in the preheat zone. 

Ammonia also poses potential water quality issues. Ammonia slip released to the atmosphere 

could contaminate surface waters by deposition. If an induration waste gas scrubber is used, 

excess ammonia could contaminate the tailings basin as water is recycled from the tailings basin 

to the plant. 

 

5. SCR – Feasible only if within SCR temperature range 

The SCR catalysts generally work only in an operating temperature range of 500 °F to 800 °F. 

The operating temperatures in induration furnaces exceed this temperature window. An 

induration furnace is designed such that the flue gas dries and pre-heats the taconite pellets. This 

is accomplished using blowers and ductwork to move the hot gases from the induration furnace 

to the pellet pre heat section. As the induration flue gas heats the taconite pellets, its temperature 

drops. In order for SCR to work, there must be a point in the ductwork that is within the SCR 

operating temperature range. Therefore, it is unlikely that an appropriate temperature window for 

SCR exists within the induration furnace system. Alternatively, the exhaust gas must be reheated in order for this technology to be considered technically feasible. 

If SCR is used in combination with a PM control device on the induration waste gas stream, it 

may be possible to install the SCR upstream of particulate controls. SCR systems for coal power 

plants have been designed to operate upstream of particulate controls. In this case, structured 

SCR catalyst blocks are used, and soot blowing can be used to prevent catalyst bed plugging. 

As noted above, ammonium sulfate salt plugging is a potential issue if sufficient sulfur oxides 

and ammonia are present in the preheat section of the induration furnace. This issue should be 

carefully reviewed in the site-specific analysis. 

6. Ported kilns – Feasible only for grate/kiln systems 

Two ported grate/kiln systems are currently in operation. This technology has not been 

researched and is not commercially available for straight grate furnaces. 

7.3.3 BART Step 3: Rank Remaining Control Technologies 

The remaining control technologies and their control efficiencies are presented in Table 7-3. 
64

Table 7-3 

Control Technology Rankings for Induration NOx Control 

Control Technology 

Control 

Efficiency 

1. SCR 70% to 90% 

2. IFGR Burners 50% 

3. Low-NOx Burners 25% 

4. Ported Kiln > 5% 

7.3.4 BART Step 4: Evaluate Impacts and Document the Results 

A discussion of relevant impacts, including (A) economic, (B) environmental, and (C) energy, 

for each of the four technically feasible control technologies is detailed below. A summary of the 

impacts and the control cost calculation sheets are located in Attachment I. 

1A. SCR economic impacts 

The hardware for a SCR system includes catalyst materials; the ammonia system including a 

vaporizer, storage tank, blower or compressor, and various valves, indicators, and controls; the 

ammonia injection grid; the SCR reactor housing (containing layers of catalyst); transition 

ductwork; and a continuous emissions monitoring system. Costs may vary nominally if aqua 

ammonia or urea is used instead of anhydrous ammonia. 

Potential site-specific costs not included but that may be necessary are additional particulate 

removal equipment and ductwork for a control equipment bypass. Taconite plants often have 

mechanical particulate removal devices to protect process blowers. If mechanical cleaners are 

not present, additional gas cleaning may be needed for SCR. Steam boilers often have bypasses 

on SCR systems to protect them during startup, shutdown, and malfunction conditions, which 

could damage the SCR catalyst. 

The pollution control costs for SCR are calculated in two ways: 

1. Tying an SCR reactor into an existing induration furnace pre-heat duct system. 

2. Installing an SCR reactor with a re-heat system on the induration waste gas stream. 

The calculations show that option 1 has a much lower control cost than option 2. However, for 

option 1 to be technically feasible, there must be a point in the pellet pre-heat section ductwork 

that meets the SCR operating temperature range. As mentioned in the technical feasibility step of 

the evaluation, it is unlikely that the temperature range will be met because the existing preheat 

systems have not been designed with this in mind. Re-designing the pre-heat section for 

installation of SCR is outside the intent of BART in accordance with the proposed EPA 

rulemaking. 

Option 2 costs are estimated using EPA cost formulas for a recuperative thermal oxidizer with 

70% heat recovery in conjunction with an SCR reactor. An actual design would most likely 
65

include a duct burner to re-heat the waste gas and a heat exchanger for heat recovery. Waste gas 

re-heat is required because the exhaust gas is too cool for SCR operating temperature. 

One potential option for reducing the cost of waste gas re-heat is installation of a heat exchanger 

to recover heat from the pellet cooler exhaust. In addition to a heat exchanger, this option could 

incur significant costs for duct work and larger air blowers. The potential for fouling the 

exchanger from dust should also be evaluated. Each facility will have to determine if this option 

is feasible on a site-specific basis. 

The model calculations, assuming a 90% NOx reduction, suggest that further investigation of 

Option 2 is warranted in the grate/kiln high inlet NOx concentration (175 ppm) case. Note that 

the model calculations for the low inlet NOx concentration (50 ppm) case may be low, since it 

may be difficult to achieve a 90% reduction due to the low NOx concentration at the SCR inlet. 

1B. SCR environmental impacts 

Undesirable reactions can occur in an SCR process, including the oxidation of NH3 and SO2 to 

form sulfate salts. These compounds are corrosive and can be deposited on the exhaust duct 

walls. In addition, ammonium sulfate and ammonium bisulfate condense at temperatures below 

400 °F, forming white solids, which will increase particulate emissions. 

Ammonia slip, or un-reacted ammonia, is also a problem with SCR. Ammonia concentrations in 

the exhaust gas are typically in the 5-ppm to 10-ppm range. Ammonia can react with sulfur and 

nitrogen oxides to form fine particulate matter that contributes to haze. In addition, storage of 

anhydrous ammonia can pose some environmental and safety risks associated with the potential 

for an accidental release. Aqua ammonia and urea may be substituted for ammonia; but these 

systems have higher capital and operating costs than anhydrous ammonia. 

Ammonia also poses potential water quality issues. Ammonia slip released to the atmosphere 

could contaminate surface waters by deposition. If an induration waste gas scrubber is used, 

excess ammonia would be absorbed by the scrubber. This could contaminate the tailings basin as 

water is recycled from the tailings basin to the plant. 

1C. SCR energy impacts 

Additional natural gas may be required if a duct burner is needed to maintain proper catalyst bed 

temperatures. 

2A and 3A. Low-NOx and IFGR burner economic impacts. 

The cost for installation of new burners is assumed to be relatively low. This estimate assumes a 

minor amount of refractory work and natural gas piping revisions will be needed. Two burner 

sizes were evaluated to reflect the range of burner that may be installed. 

Low-NOx and IFGR burner tiles can be significantly larger than standard burner tiles, leading to 

extensive refractory work. Sometimes the size of the burner tile can be large enough to require 

structural changes to the furnace. These factors should be evaluated in the site-specific analysis. 
66

Low-NOx and IFGR Burners typically have longer flame patterns than standard burners. The 

impact of longer flames should be evaluated when considering the cost of installation for these 

burners. 

Installation of low NOx Burners is a potential option if the induration furnace uses gas burners to 

pre-heat the pellets. The NOx reductions for this case are based an emission factor of 0.14 

lb NOx per MMBtu of gas firing and control efficiencies of 25% and 50% for Low-NOx and 

IFGR burners, respectively.20 Pyrolysis heaters operate in the same temperature range as pellet 

pre-heating, but with much lower excess air conditions than induration furnaces. So, it is unlikely 

that the same level of emission reduction in a pyrolysis heater can be achieved in an induration 

furnace. 

The overall reduction in NOx emissions due to low NOx burners must be determined on a sitespecific basis. The control efficiency for low NOx burners used in the economic analysis is for 

the burners themselves, not for the overall induration process. The percentage reduction in total 

induration furnace NOx emissions will be lower because only a fraction of the total fuels burned 

in the induration furnace is combusted in low NOx burners. The overall NOx reduction for low 

NOx burners will be proportional to the percentage of fired duty which is supplied by the low 

NOx burners. For example, the Low NOx cost calculations show a reduction of 20 to 40 tons per 

year of NOx from an uncontrolled emission rate of 70 ton/yr NOx for the burners. In contrast, 

total NOx for the model induration sources ranges from 300 to 13,500 tons of NOx per year. 

2B and 3B. Low-NOx and IFGR burner environmental impacts 

There are no known adverse environmental impacts associated with these burners. 

2C and 3C. Low-NOx and IFGR burner energy impacts 

Some IFGR burners are slightly less energy efficient that standard burners. A nominal increase 

in natural gas consumption may occur. 

4A, 4B, and 4C. Ported kilns economic, environmental, and energy impacts 

The primary benefits of ported kilns are a 5% reduction in fuel use and an improvement in pellet 

quality. The main driver for installation of ported kilns is the economic benefit of reduced fuel 

consumption. Due to the marginal environmental benefits of ported kilns, a cost analysis was not 

performed. 

7.4 Model Induration Furnace SO2 Control Technology Review 

SO2 emissions from the induration furnaces are mostly due to fuel combustion. Some SO2 may 

also be emitted from oxidation of sulfur compounds in the iron ore. 

As shown in Section 9 of this report, no specific regulatory limits for SO2 emissions exist for 

taconite induration furnaces. However, Minnesota rules govern SO2 emissions from direct-fired 

equipment, such as induration furnaces, to the following limitations: 

 

20 Derived from pyrolysis heaters in “Alternative Control Techniques Document – NOx Emissions from Process 

Heaters (Revised),” US EPA, EPA-453/R-93-034, September 1993. 
67

• SO2 emissions from liquid fuels: 2.0 lbs of SO2 per 1 million BTU. 

• SO2 emissions from solid fuels are limited to 4.0 lbs of SO2 per 1 million BTU. 

These limits can be achieved through fuel quality and do not impact the BART screening 

evaluation. 

7.4.1 BART Step 1: Identify All Available Retrofit Control Technologies 

Control technologies available for SO2 are as follows: 

• High-efficiency and low-efficiency wet scrubbers 

• Wet walled electrostatic precipitator (WWESP) 

See Section 6.2 for additional information on these control technologies and additional 

technologies identified in the literature search. 

7.4.2 BART Step 2: Eliminate Technically Infeasible Options 

Both of the control technologies identified in step 1 are deemed technically feasible. The 

WWESP is currently used to control emissions at some existing taconite induration furnaces. 

Wet particulate scrubbers, which are similar to the wet scrubbers for SO2, are also used at some 

existing induration furnaces. 

7.4.3 BART Step 3: Rank Remaining Control Technologies 

The technically feasible control technologies and their control efficiencies are presented in 

Table 7-4. 

Table 7-4 

Control Technology Rankings for Induration SO2 Control 

Control Technology 

Control 

Efficiency 

1. High Efficiency Wet 

Scrubber 

95% 

2. Low Efficiency Wet 

Scrubber 

80% 

3. WWESP 80% 

7.4.4 BART Step 4: Evaluate Impacts and Document the Results 

A discussion of relevant impacts, including (A) economic, (B) environmental, and (C) energy, 

for the technically feasible control technologies is detailed below. A summary of the impacts and 

the control cost calculation sheets are located in Attachment J 
68

A. Economic impacts 

For the high efficiency and low efficiency wet scrubber, the control cost calculations are 

prepared using caustic as the base in the scrubbing liquor. Lime and limestone are potential 

alternatives for a scrubber; but additional equipment will be needed for slurry preparation and for 

solids separation from the sludge generated in the scrubber. Materials of construction must also 

be made suitable for caustic, lime, or limestone if existing equipment is modified for wet 

scrubbing of SO2. 

Both the low efficiency wet scrubber and the WWESP have the option of being used to control 

SO2 and PM. To account for this dual pollutant-control purpose, two example cost calculations 

are presented in Attachment J. These tables calculate the control cost based on the removal of 

both SO2 and PM at nominal control efficiencies. Note that this may not be achievable in 

practice for existing equipment if the materials of construction are not appropriate for caustic, 

lime, or limestone addition. Lime and limestone have the added problems of high solids content 

scrubbing liquor and sludge separation. 

Model source control costs for a straight grate furnace are very high due to the low inlet 

concentration of SO2. These furnaces are generally fired on natural gas. Similarly, source control 

costs are high for most grate/kiln furnaces with low inlet SO2 waste gas concentrations. For those 

grate/kiln furnaces with high SO2 waste gas concentrations, control costs appear to be similar for 

wet scrubbers and WWESPs. Facilities should evaluate the control option that best fits their 

existing infrastructure in order to minimize overall control costs. 

B. Environmental impacts 

The primary environmental impact of wet scrubbers is the generation of wastewater and sludge. 

Waste from the scrubber will increase the sulfate and solids loading in the facility’s wastewater. 

This places additional burdens on a facility’s wastewater treatment and solid waste management 

capabilities. These impacts will need to be analyzed on a site-specific basis. If lime or limestone 

scrubbing is used to produce calcium sulfite sludge, the sludge is water-laden, and it must be 

stabilized for land filling. If lime or limestone scrubbing is used to produce calcium sulfate 

sludge, it is stable and easy to dewater. However, control costs will be higher because additional 

equipment is required. 

Scrubber and WWESP exhaust gases are saturated with water, thus creating a visible plume. 

Plume visibility may be a local/community concern. Once the exhaust mixes with sufficient air, 

the moisture droplets evaporate, and the plume is no longer visible. 

C. Energy impacts 

A scrubber operates with a high pressure drop, resulting in a significant amount of electricity 

required to operate the blower and pump. In comparison, the WWESP has a lower pressure drop 

requirement than the scrubber and the cost to operate the electrical field is not as significant as 

the electrical costs for the wet scrubber. 
69

7.5 Model Induration Furnace PM Control Technology Review 

Particulate matter emissions emanate from both fuel combustion, especially if a solid fuel is 

used, and the attrition of particles (dust) in the taconite pellets. 

Federal and State regulations govern PM emissions at taconite induration furnaces. Table 7-5 

summarizes applicable emission limits. 

Table 7-5 

Applicable PM and Opacity Emission Limitations at Taconite Induration Furnaces 

Pollutant Emission Limit 

Regulatory 

Reference 

Particulate Matter 0.010 gr/dscf existing straight 

grate induration processing 

magnetite 

Proposed 40 CFR 63 Subpart 

RRRRR – MACT 

Particulate Matter 0.011 gr/dscf existing grate/kiln 

induration processing magnetite 

Proposed 40 CFR 63 Subpart 

RRRRR – MACT 

Particulate Matter 0.026 gr/dscf existing grate/kiln 

induration processing hematite 

Proposed 40 CFR 63 Subpart 

RRRRR – MACT 

Visible Emissions 20% opacity MN 7011.7010 & 7015 

Pre & Post 1969 Industrial 

Process Rules 

Particulate Matter 0.02 to 0.3 gr/dscf 

Limit based on exhaust flow and 

production capacity 

MN 7011.7010 & 7015 

Pre & Post 1969 Industrial 

Process Rules 

7.5.1 BART Step 1: Identify All Available Retrofit Control Technologies 

Control technologies available for PM are as follows: 

• High Efficiency and Low Efficiency Wet Scrubber 

• Dry Electrostatic Precipitator (ESP) 

• Wet Wall Electrostatic Precipitator (WWESP) 

• Fabric Filter (Baghouse) 

• Multiclone 

See Section 6.3 for additional information on these control technologies and additional 

technologies identified in the literature search. 

7.5.2 BART Step 2: Eliminate Technically Infeasible Options 

All control technologies identified in step 1 are deemed technically feasible except for the fabric 

filters (baghouses). Many sources currently use wet particulate scrubbers or WWESPs. 
70

Fabric filters are infeasible in this application due to filter blinding associated with water 

condensation. Currently, no taconite plants in the United States use fabric filters for particulate 

control on induration furnaces. The process designs for induration furnaces include provisions 

for energy recovery by using hot process gas to pre-heat and dry the incoming green taconite 

pellets. To maximize energy recovery, the furnaces were designed so that gases leaving the 

induration furnace are typically in the 100 °F to 150 °F range. This leaves the stack gases at or 

very near their dew points. Any free water present in the induration furnace waste gas or water 

condensation on the filter media would create a wet and sticky filter cake that would not be 

easily be removed from the filters. Other control technology options that are technically feasible 

can provide comparable emission control efficiency; therefore, elimination of fabric filter 

technology will not significantly affect the BART screening evaluation. 

7.5.3 BART Step 3: Rank Remaining Control Technologies 

The third of the five steps in the top-down BART analysis is to rank the remaining control 

technologies by control effectiveness. The remaining control technologies and their control 

efficiencies are presented in Table 7-6. 

Table 7-6 

Control Technology Rankings for Induration PM Control 

Control Technology 

Control 

Efficiency 

1. Dry ESP 98%-99+% 

2. WWESP 98%-99+% 

3. Wet Scrubber High Efficiency 95%-99+% 

4. Wet Scrubber Low Efficiency 90%-95% 

5. Multiclone 50%-80% 

7.5.4 BART Step 4: Evaluate Impacts and Document the Results 

A discussion of relevant impacts, including (A) economic, (B) environmental, and (C) energy, 

for each of the five technically feasible control technologies is detailed below. A summary of the 

impacts and the control cost calculation sheets are located in Attachment K. 

A. Economic impacts 

Model source control costs for a straight grate furnace are high due to the low inlet concentration 

of PM. These furnaces are generally fired on natural gas. Model source control costs for 

grate/kiln furnaces were lower due to higher PM concentrations in the induration waste gas. 

Control costs for ESP appear to be significantly higher than other PM control technologies. 

Note that the same capital cost estimate is used for high efficiency and low efficiency scrubbers. 

Based on an analysis performed in 2001 for a potential new taconite plant, the cost 

differentiation between high efficiency and low efficiency scrubbers is insignificant. In practice, 
71

a low efficiency scrubber will have a lower capital cost than a high efficiency scrubber, but the 

cost difference will likely not be significant. 

Another cost consideration is the estimated PM10 removal efficiency for multiclones. The 

BART screening evaluation uses 80% control efficiency to determine the control cost. Cyclones 

generally do not control fine particulate matter as well as other PM control technologies. Vendor 

guarantees for control efficiency should be verified; especially when multiclone inlet PM loading 

consists primarily of fine particulate matter. Particle size distribution for the waste gas steam 

may be necessary to accurately predict the particulate matter control efficiency. In some cases, 

the waste gas inlet PM concentrations may be below the level necessary for a multiclone to 

effectively remove PM. 

As noted in the BART screening evaluation for SO2 emissions, both wet scrubbers and WWESPs 

may potentially be used to remove both PM and SO2. The option should be considered in the 

site-specific BART analysis. 

B. Environmental impacts 

The primary environmental impact of wet scrubbers is the generation of wastewater and sludge. 

Waste from the scrubber will increase the sulfate and solids loading in the facility’s wastewater. 

This places additional burdens on a facility’s wastewater treatment and solid waste management 

capabilities. These impacts will need to be analyzed on a site-specific basis. 

Scrubber and WWESP exhaust gases are saturated with water, thus creating a visible plume. 

Plume visibility may be a local/community concern. Once the exhaust mixes with sufficient air, 

the moisture droplets evaporate, and the plume is no longer visible. 

A dry ESP and a multiclone will both generate solid waste from the material collected in the 

associated hopper. 

C. Energy impacts 

A scrubber operates with a high pressure drop, resulting in a significant amount of electricity 

required to operate the blower and pump. In comparison, the WWESP has a lower pressure drop 

requirement than the scrubber and the cost to operate the electrical field is not as significant as 

the electrical costs for the wet scrubber. Similarly, a relatively modest amount of electricity is 

required for multiclone blower operation. 

7.6 Model Pellet Cooler PM Control Technology Review 

Particulate matter emissions emanate primarily from the attrition of particles (dust) in the 

taconite pellets. 

Table 7-5 lists PM and opacity emission limitations at taconite induration furnaces. The proposed 

Taconite MACT standards in this table do not apply to pellet cooler vent stacks. However, the 

Minnesota rules regulating industrial process equipment, as shown in this table, is applicable to 

the pellet coolers. 
72

The control technology review for pellet cooler PM emissions is similar to the review for 

induration PM emissions in Section 6.3. 

7.6.1 BART Step 1: Identify All Available Retrofit Control Technologies 

Control technologies available for PM are the same as those identified in Section 7.5.1 for the 

model induration furnace. These technologies are as follows: 

• High Efficiency and Low Efficiency Wet Scrubber 

• Dry Electrostatic Precipitator (ESP) 

• Wet Wall Electrostatic Precipitator (WWESP) 

• Fabric Filter (Baghouse) 

• Multiclone 

See Section 6.3 for additional information on these control technologies and additional 

technologies identified in the literature search. 

7.6.2 BART Step 2: Eliminate Technically Infeasible Options 

All control technologies identified in step 1 are deemed technically feasible. However, if an 

existing pellet cooler uses a wet scrubber or WWESP, a fabric filter is technically infeasible for 

the same basis as that described in Section 7.5.2 for a fabric filter on an induration furnace. Note 

that the wet scrubber or WWESP would already control PM emissions to a level similar to a 

fabric filter. 

7.6.3 BART Step 3: Rank Remaining Control Technologies 

The third of the five steps in the top-down BART analysis is to rank the remaining control 

technologies by control effectiveness. The remaining control technologies and their control 

efficiencies are presented in Table 7-7. 
73

Table 7-7 

Control Technology Rankings for Pellet Cooler PM Control 

Control Technology Control Efficiency 

1. Fabric Filter 98%-99+% 

2. Dry ESP 98%-99+% 

3. WWESP 98%-99+% 

4. Wet Scrubber High Efficiency 95%-99+% 

5. Wet Scrubber Low Efficiency 90%-95% 

6. Multiclone 50%-80% 

7.6.4 BART Step 4: Evaluate Impacts and Document the Results 

A discussion of relevant impacts, including (A) economic, (B) environmental, and (C) energy, 

for each of the six technically feasible control technologies is detailed below. A summary of the 

impacts and the control cost calculation sheets are located in Attachment L. 

A. Economic impacts 

Model source control costs for pellet coolers are relatively low due to significant PM inlet 

loading at the pellet cooler exhaust. Control costs seem to be similar between the different 

control types. Facilities should evaluate the control option that best fits their existing 

infrastructure in order to minimize overall control costs. Actual control costs will be higher than 

the model source for those emission units that have existing controls and resultant lower PM 

loadings. 

Note that the same capital cost estimate is used for high efficiency and low efficiency scrubbers. 

Based on an analysis performed in 2001 for a potential new taconite plant, the cost 

differentiation between high efficiency and low efficiency scrubbers is insignificant. In practice, 

a low efficiency scrubber will have a lower capital cost than a high efficiency scrubber, but the 

cost difference will likely not be significant. 

Another cost consideration is the estimated PM10 removal efficiency for multiclones. The 

BART screening evaluation uses 80% control efficiency to determine the control cost. Cyclones 

generally do not control fine particulate matter as well as other PM control technologies. Vendor 

guarantees for control efficiency should be verified; especially when multiclone inlet PM loading 

consists primarily of fine particulate matter. In some cases, the waste gas inlet PM concentrations 

may be below the level necessary for a multiclone to effectively remove PM. 

B. Environmental impacts 

The primary environmental impact of wet scrubbers is the generation of wastewater and sludge. 

Waste from the scrubber will increase the sulfate and solids loading in the facility’s wastewater. 

This places additional burdens on a facility’s wastewater treatment and solid waste management 

capabilities. These impacts will need to be analyzed on a site-specific basis. 
74

Scrubber and WWESP exhaust gases are saturated with water, thus creating a visible plume. 

Plume visibility may be a local/community concern. Once the exhaust mixes with sufficient air, 

the moisture droplets evaporate, and the plume is no longer visible. 

A dry ESP, multiclone, and fabric filter will all generate solid waste from the material collected 

in the associated hopper. 

C. Energy impacts 

A scrubber operates with a high pressure drop, resulting in a significant amount of electricity 

required to operate the blower and pump. In comparison, the WWESP has a lower pressure drop 

requirement than the scrubber and the cost to operate the electrical field is not as significant as 

the electrical costs for the wet scrubber. Similarly, a relatively modest amount of electricity is 

required for multiclone and fabric filter blower operation. 

7.7 Model Material Ore Material Handling PM Control Technology 

Review 

Material handling, crushing, and screening activities are grouped together for the model BART 

screening evaluation. Physical characteristics of the model iron ore material handling source are 

described in Table 7-1. 

Federal and State regulations govern PM emissions at material handling sources. Table 7-8 

summarizes applicable emission limits. In addition, Minnesota rules and the proposed taconite 

MACT require a fugitive dust control plan. 

Table 7-8 

Applicable PM and Opacity Emission Limitations at Ore Material Handling Sources. 

Pollutant Emission Limit 

Regulatory 

Reference 

Particulate Matter 0.02 gr/dscf 40 CFR 60.382(a)(1) - NSPS 

Visible Emissions 7% opacity from process point 

sources (exemption for wet 

scrubber) 

40 CFR 60.382(a)(2) - NSPS 

Visible Emissions 10% opacity from process 

fugitive sources 

40 CFR 60.382(b) - NSPS 

Particulate Matter 0.008 gr/dscf at an existing 

source 

Proposed 40 CFR 63 Subpart 

RRRRR – MACT 

Visible Emissions 20% opacity MN 7011.7010 & 7015 

Pre & Post 1969 Industrial 

Process Rules 

Particulate Matter 0.02 to 0.3 gr/dscf 

Limit based on exhaust flow and 

production capacity 

MN 7011.7010 & 7015 

Pre & Post 1969 Industrial 

Process Rules 

7.7.1 BART Step 1: Identify All Available Retrofit Control Technologies 

Control technologies available for PM are as follows: 
75

• High Efficiency and Low Efficiency Wet Scrubber 

• Dry Electrostatic Precipitator (ESP) 

• Wet Wall Electrostatic Precipitator (WWESP) 

• Fabric Filter (Baghouse) 

• Multiclone 

• Enclosure 

• Wet Suppression 

• Best Management Practices 

See Section 6.3 for additional information on these control technologies and additional 

technologies identified in the literature search. 

7.7.2 BART Step 2: Eliminate Technically Infeasible Options 

Table 7-9 summarizes the technical feasibility of each available control technology to ore 

material handling sources. 

Table 7-9 

Summary of Technical Feasibility for Ore Material Handling PM Emissions 

Control Technology 

Feasibility 

Determination

Issues That Affect 

Control Technology Feasibility 

1. Wet Scrubber High & 

Low Efficiency 

Conditionally 

Feasible 

It must be feasible to enclose the source and duct the 

exhaust to the control device. 

2. Dry ESP Conditionally 

Feasible 

It must be feasible to enclose the source and duct the 

exhaust to the control device. 

3. WWESP Conditionally 

Feasible 

It must be feasible to enclose the source and duct the 

exhaust to the control device. 

4. Fabric Filter (Baghouse) Conditionally 

Feasible 

It must be feasible to enclose the source and duct the 

exhaust to the control device. 

5. Multiclone Conditionally 

Feasible 

It must be feasible to enclose the source and duct the 

exhaust to the control device. 

6. Enclosure Conditionally 

Feasible 

Feasible for conveyor drops into processing equipment 

on onto other conveyors. Not feasible for conveyor drops 

onto large storage piles. Telescoping chutes may be 

feasible. 

7. Wet Suppression Conditionally 

Feasible 

For use on fugitive sources such as storage piles. 

Effectiveness will be limited in active areas where 

material surfaces are disturbed on a frequent basis. May 

also be used on conveyors to bind up particulates before 

the transfer material is dropped off the conveyor.21 

8. Best Management 

Practices 

Conditionally 

Feasible 

For use on fugitive sources such as storage piles. 
76

Some material handling sources utilize existing wet scrubbers. In this case, there will be water 

mist in the exhaust, and the used of fabric filters is infeasible. 

7.7.3 BART Step 3: Rank Remaining Control Technologies 

The third of the five steps in the top-down BART analysis is to rank the remaining control 

technologies by control effectiveness. The remaining control technologies and their control 

efficiencies are presented in Table 7-10. 

Table 7-10 

Control Technology Rankings for Ore Material Handling PM Control 

Control Technology Control Efficiency 

1. Fabric Filter 98%-99+% 

2. Dry ESP 98%-99+% 

3. WWESP 98%-99+% 

4. Wet Scrubber High Efficiency 95%-99+% 

5. Wet Scrubber Low Efficiency 90%-95% 

6. Chemical Stabilization 75%-80% 

7. Multiclone 50%-80% 

8. Enclosure (Windbreaks may also 

be used to minimize the impact of 

wind entrainment of particulates.) 

50%-100% 

9. Wet Suppression 50%-75% 

10. Best Management Practices 

(e.g., minimize drop heights, work on 

lee side of piles, minimize disturbed 

area) 

Variable 

7.7.4 BART Step 4: Evaluate Impacts and Document the Results 

A discussion of relevant impacts, including (A) economic, (B) environmental, and (C) energy, 

for each of the four technically feasible control technologies is detailed below. A summary of the 

impacts and the control cost calculation sheets are located in Attachment M. 

A. Economic impacts 

The emission basis for this model source is the AP-42 factor for uncontrolled drops of aggregate 

materials (i.e. iron ore). The same baseline emission rate is used for all control options. 

Enclosures and multiclones have the lowest control costs for the model source. Dry and wet 

walled ESPs have the highest control costs. The multiclone estimate was based on grouping ten 

sources together because the multiclone vendor could not prepare a quote for such a small 

source. Where applicable, data from the cost analysis table (M-7) summary table was divided by 

10 in the summary table (M-1) so that the information would be comparable to the other control 

methods. An 80% control efficiency was assumed for multiclone control cost calculations. 

Actual control efficiencies are likely to be lower; so, vendor control efficiency guarantees should 

be obtained for the site-specific analysis. 
77

The cost control estimates for control equipment assumes that an enclosure is in place to connect 

the emission unit to the control device. If an uncontrolled source without an enclosure is 

evaluated, the control cost should include the cost of an enclosure. 

Many facilities currently control emissions from conveyor drops. Often, several sources are 

ducted to a single control device. This reduces overall control costs by taking advantage of the 

economy of scale for a relatively expensive piece of control equipment. Facilities should 

consider this option when evaluating their material handing emissions. 

Control costs are not calculated for wet suppression or best management practices. Most 

facilities have already incorporated these practices into their particulate control plans. 

B. Environmental impacts 

The primary environmental impact of wet scrubbers is the generation of wastewater and sludge. 

Waste from the scrubber will increase the sulfate and solids loading in the facility’s wastewater. 

This places additional burdens on a facility’s wastewater treatment and solid waste management 

capabilities. These impacts will need to be analyzed on a site-specific basis. 

Scrubber and WWESP exhaust gases are saturated with water, thus creating a visible plume. 

Plume visibility may be a local/community concern. Once the exhaust mixes with sufficient air, 

the moisture droplets evaporate, and the plume is no longer visible. 

A dry ESP, multiclone, and fabric filter will all generate solid waste from the material collected 

in the associated hopper. 

C. Energy impacts 

A scrubber operates with a high pressure drop, resulting in a significant amount of electricity 

required to operate the blower and pump. In comparison, the WWESP has a lower pressure drop 

requirement than the scrubber and the cost to operate the electrical field is not as significant as 

the electrical costs for the wet scrubber. Similarly, a relatively modest amount of electricity is 

required for multiclone and fabric filter blower operation. 

7.8 Fugitive Dust Emissions 

Fugitive dust emissions occur from the mechanical disturbance of granular material exposed to 

the air. These emissions are termed “fugitive” because that are not discharged to the atmosphere 

in a confined flow stream. The dust-generation process is caused by two basic physical 

phenomena: 

1. Pulverization and abrasion of surface materials by application of mechanical force 

through implements. 

2. Entrainment of dust particles by the action of turbulent air currents. 
78

Sources of fugitive emission at taconite plans include unpaved roads, storage piles, loading and 

unloading operations, tailings basins, and drops. 

Control methods for fugitive emissions are listed in this section for informational purposes only. 

Most fugitive particulate emissions occur in the mining area, which is considered outside the 

scope of this screening BART analysis. It is also anticipated that fugitive emissions will not 

disperse great distances to impact visibility in a Class I area. 

Minn. Rule 7011.0150 requires sources to control fugitive particulate emissions at their facilities. 

Minn. Rule 7007.0800 establishes particulate control requirements in the facility’s operating 

(Title V) permit. 

Available control technologies for PM control from fugitive dust emissions are identified in 

Table 7-11. 

Table 7-11 

Available PM Control Technologies for Fugitive Sources 

Process Control Technology 

1. Vehicle Traffic Wet Suppression 

Physical Stabilization 

Cover Roads with Low Silt Gravel 

Paved Surface Cleaning 

Limit speeds and area of travel 

2. Overburden Wind Erosion and 

Waste Rock Wind Erosion 

Minimize the Area of Disturbance 

Physical Stabilization 

Vegetative Stabilization 

Wind Breaks – fences, soil mounds or 

trees 

3. Tailings Basin Physical Stabilization 

Vegetative Stabilization 

Wet Suppression 

All taconite plants have fugitive dust control plans in place, as required by Minn. Rule 

7011.0150. The plans include control measures like the ones listed above to manage fugitive 

emissions. The control plans updated and reviewed by MPCA as part of the Title V permit reissuance process that occurs every five years. 
79

8 Affordability 

BART development provides for an affordability analysis of the proposed case-by-case BART 

evaluation. The affordability analysis is to consider the effects of BART on the viability of 

continued plant operations. This analysis may allow that the total cost of a BART program at the 

plant be considered as discussed below. Financial information adequate to assess the viability of 

the BART program must also be provided. The affordability analysis will then need to include an 

evaluation of the economic impacts of the proposed BART alternative to the source under 

consideration. The analysis will need to be in sufficient detail to provide a compelling argument 

regarding the plant viability for the proposed BART. 

8.1 BART Alternative Cost Inventory 

Total costs associated with a BART alternative can be considered in an affordability analysis. 

Items to consider in developing a total cost inventory may include: 

Control Associated Costs. These include capital costs and operation and maintenance costs 

associated with the BART alternative. It may include water and solids management, energy 

and other costs that are also directly associated with the control alternative. This is discussed 

in Section 7. Several members of the taconite industry and the industry organization were 

contacted to ascertain their perspectives. The industry representatives are unable to predict 

whether the controls likely to be required to meet BART would be more stringent than 

existing or imminent future requirements. Without knowing the level of control BART would 

require, they were unable to provide any information on its affordability. 

Compliance Associated Costs. This includes the costs required to demonstrate compliance 

with the proposed BART emissions limit or operating practice. Examples include additional 

emissions testing, operations monitoring, records management, and compliance reporting 

related costs for the proposed BART alternative. Several members of the taconite industry 

and the industry organization were contacted to ascertain their perspectives. The industry 

representatives are unable to predict whether the monitoring and testing likely to be required 

to meet BART would be more stringent than existing or imminent future requirements. 

Without knowing the level of monitoring BART would require, they were unable to provide 

any information on its affordability. 

Supplier Price Increases. The Regional Haze program is likely to require air emissions 

reductions at suppliers to the taconite industry. It is possible that supplier’s product prices 

may be increased to recover the costs of their emission reduction efforts. These price 

increases may be considered in determining the affordability of proposed emissions reduction 

alternatives under consideration in establishing BART for the taconite plants. Major 

potentially affected suppliers include fossil fuels and electricity. Electric and petroleum fuel 

producers that are the major suppliers of these services to the Minnesota taconite industry 

were contacted. However, they were unable to provide an estimate of the costs of the 

Regional Haze program or potential product price increases at this time due to the 

uncertainties and long time-line associated with implementation of the Regional Haze 

program. 
80

Other BART Related Costs. Any other costs that would be attributed to the BART program 

and that may affect the viability of the organization may also be included in the cost 

inventory. 

8.2 Financial Information Inventory 

Significant resources within the Minnesota taconite industry are in bankruptcy or on the verge of 

it. The industry faces tough competition from foreign sources.21 The US mines have higher 

production costs in part because of the higher cost of labor and greater taxation. The high cost of 

transportation through the St. Lawrence Seaway prevents US taconite from entering the world 

steel market and levels the playing field somewhat with foreign taconite destined for US 

steelmakers, although the delivered cost of foreign taconite remains cheaper. 

The cost of closing a taconite mine essentially traps producers into operating their mines well 

past what their operating costs would justify.22 Environmental and employee closure costs are 

significant. Environmental closure costs are expected to be postponed, passed on to the next 

operator, or be foregone in a final bankruptcy liquidation. Retirement and health care costs for 

employees at closure are expected to be delayed by continuing to operate mines even after they 

become unprofitable. The US government may step in, but so far has not. If a BART program led 

to significant cost increases, the viability of the industry would be seriously threatened. 

Broad industry related financial information and plant specific information that is current at the 

time of the site-specific affordability analysis will be required. This should include the following 

information: 

Financial Statements. A description of the plant ownership should be provided along with the 

financial statement of each corporation that has an ownership stake in the plant. 

Financial Reports for the Individual Taconite Plant. At a minimum, the current balance 

sheet, income statement, and cash flow statement should be provided. 

Independent Market Analysis of the Industry. This includes a long term and short tem 

analysis completed by an independent entity. 

Other Relevant Information. Other relevant information as necessary to support the argument 

regarding viability concerns of the entity under consideration. Relevant information to 

evaluate effects on market share, product prices, and profitability should be considered. 

8.3 Affordability Evaluation Summary 

The affordability evaluation will be required to make a compelling argument regarding the plant 

viability based on information that is current at the time of the BART-decision making process. 

The analysis will likely involve the review and presentation of sensitive business information. To 

 

21 Cost Comparison for North American Iron Ore Mines – Part II, Skillings Mining Review, December 2002. 22 IBID 
81

assure the confidentiality of the sensitive information, a confidentiality request must be filed that 

meets the requirements of Minnesota Statutes. 
82

9 Summary of Existing and Proposed Air Pollution 

Regulatory Requirements 

This section provides a summary of the existing and proposed federal regulations and existing 

state and Canadian provincial air pollution regulatory requirements that are applicable to the 

three taconite emission unit categories established in Section 5.8.2. The regulations summarized 

include: 

• 40 CFR 60, Subpart LL – Standards of Performance for Metallic Mineral Processing 

Plants 

• 40 CFR 60, Subpart Y – Standards of Performance for Coal Preparation Plants 

• 40 CFR 63, Subpart RRRRR – National Emission Standards for Hazardous Air Pollutants 

(NESHAPs) for Taconite Iron Ore Processing 

• Minnesota Rules, Chapter 7011 – Standards for Stationary Sources 

• Michigan Air Pollution Control Rules, Parts 3 through 12 

• Canadian provincial air pollution control regulations. 

Existing air permits as well as past BACT determinations at the Minnesota taconite plants were 

also reviewed for any site-specific emission limitations. Findings from the air permit review are 

included throughout this section and are referred to as permit limits under Minn. R. 7007.0800. 

See Section 9.7 for a summary of relevant BACT determinations. 

The information and findings detailed in this section are summarized in Tables 9-1, 9-2, and 9-3 

with respect to each of the three taconite emission unit categories. 
83

Table 9-1 

Air Quality Standards for Taconite Fugitive Particulate Sources

Standard 

Emission Limit 

or 

Site-specific Operating Standard Comment 

40 CFR 60 

Subpart LL 

10% opacity 

Proposed 40 CFR 

63 Subpart 

RRRRR 

 Prepare and implement a written 

fugitive dust emissions control 

plan 

Minn. R. 

7007.0800 

Observe fugitive dust sources daily 

Minn. R. 

7007.0800 

Comply with the fugitive control plan 

Minn. R. 

7007.0800 

Ensure 1 employee trained to perform 

visible emissions checks 

Minn. R. 

7007.0800 

Comply with the operation and 

maintenance plan 

Minn. R. 

7011.0150 

 Avoid particulate matter from 

becoming airborne 

MI R 336.1371 Submit a fugitive dust control 

program 

Quebec Dust control measures for 

transport areas 

Quebec 50 mg/m3 or 2 m free fall height Free fall of materials 

Quebec 2 m from source Dust recuperated by a dry 

collector 
84

Table 9-2 

Air Quality Standards for Taconite Point Particulate Sources 

Standard 

Emission Limit 

or 

Site-specific Operating Standard Comment 

40 CFR 60 

Subpart LL 

< 0.05 g/dscm (0.02 gr/dscf) 

40 CFR 60 

Subpart LL 

7% opacity 

Proposed 40 CFR 

63 Subpart 

RRRRR 

0.005 gr/dscf From new ore crushing and handling 

sources and new finished pellet 

handling sources 

Proposed 40 CFR 

63 Subpart 

RRRRR 

0.008 gr/dscf From existing ore crushing and 

handling sources and existing finished 

pellet handling sources 

Proposed 40 CFR 

63 Subpart 

RRRRR 

0.025 gr/dscf From new ore dryers 

Proposed 40 CFR 

63 Subpart 

RRRRR 

0.052 gr/dscf From existing ore dryers 

Minn. R. 

7007.0800 

Comply with the operation and maintenance 

plan 

Applies to total facility 

Minn. R. 

7007.0800 

Operate all pollution control equipment 

whenever the corresponding process 

equipment is operated 

Applies to total facility 

Minn. R. 

7007.0800 

 Install monitoring equipment for air 

pollution control devices within 180 days 

of permit issuance 

 Complete monitoring equipment 

debugging, troubleshooting, and 

establishment of parameter ranges within 

180 days of installation or of completion of 

needed repairs of all monitoring 

equipment 

 Annually calibrate all required monitoring 

equipment 

Applies to total facility 

Minn. R. 

7007.0800 

Check stack opacity once daily Applies to crushers, screens, 

conveyors, bins, blenders, grates, 

coolers, and pellet discharges 

Minn. R. Monitor gas stream pressure drop daily when Applies to fabric filters, multiclones, 
85

Table 9-2 

Air Quality Standards for Taconite Point Particulate Sources 

Standard 

Emission Limit 

or 

Site-specific Operating Standard Comment 

7007.0800 in operation scrubbers, gravity collectors 

Minn. R. 

7007.0800 

Monitor gas stream pressure drop weekly 

when in operation 

Applies to fabric filters, multiclones, 

scrubbers, gravity collectors 

Minn. R. 

7007.0800 

Monitor water flow rate or total water pressure 

daily when in operation 

Applies to scrubbers 

Minn. R. 

7007.0800 

Monitor water flow rate or total water pressure 

weekly when in operation 

Applies to scrubbers 

Minn. R. 

7007.0800 

For units controlled by fabric filters, cyclones, 

and multiclones: 

 check pressure drop daily if visible 

emissions in the plume are unreadable 

due to visible moisture 

For units controlled by scrubbers: 

 check pressure drop and total water 

pressure if visible emissions in the plume 

are unreadable due to visible moisture 

Applies to fabric filters, cyclones, 

multiclones, and scrubbers 

Minn. R. 

7007.0800 

 Operate the ambient monitors, during the 

first 12 months of haul road operation 

after permit issuance, to establish the 

operating conditions and control practices 

necessary to maintain PM-10 

concentrations at those monitors below 

the NAAQS and MAAQS. 

 The conditions and control practices 

identified during this period shall be 

incorporated into the Fugitive Control Plan 

for the facility. 

 Immediately after the time period 

described above, operate the monitors on 

a continuous 1 in 6 day sampling 

schedule to determine compliance with 

the NAAQS and MAAQS. 

 The monitors must be operated until data 

is obtained, from a total of 12 months of 

haul road operation that is below the 

NAAQS and MAAQS. After this has been 

achieved the Permittee can discontinue 

operating the monitors after notifying the 

MPCA 14 days in advance of the date the 

monitors will be shut down. 

Applies to total facility 
86

Table 9-2 

Air Quality Standards for Taconite Point Particulate Sources 

Standard 

Emission Limit 

or 

Site-specific Operating Standard Comment 

Minn. R. 

7007.0800 

Allowed to change the location of the pickup 

points to improve collection of particulates. If 

an effective location for the pickup points can 

not be found, scrubber may be removed from 

service without a permit as long as the 

unrestricted net emission change due to this 

action is not over the significant emission 

rates for PSD 

Applies to total facility 

Minn. R. 

7007.0800 

For each baghouse either, 1) make daily 

visible emission checks or pressure drop 

readings when visible emission checks can 

not be performed, or 2) operate a broken bag 

detector 

Applies to fabric filters 

Minn. R. 

7011.0710 

See process weight rate table (7011.0730 

Table 1) 

Applicable to pre-1969 industrial 

process equipment 

Minn. R. 

7011.0710 

20% opacity An exceedance of this opacity 

standard occurs whenever any onehour period contains two or more sixminute periods during which the 

average opacity exceeds 20 percent 

or whenever any one-hour period 

contains one or more six-minute 

periods during which the average 

opacity exceeds 60 percent 

Minn. R. 

7011.0715 

See process weight rate table (7011.0730, 

Table 1) 

Applicable to post-1969 industrial 

process equipment 

Minn. R. 

7011.0715 

20% opacity An exceedance occurs whenever any 

one-hour period contains one or more 

six-minute periods during which the 

average opacity exceeds 20 percent 

MI R 336.1301 20% opacity 6-minute average 

MI R 336.1331 See process weight rate table (Part 3, Table 

32) 

Newfoundland 

957/96 

Opacity: No. 1 on visible emission chart Except No. 2 for < 4 min in 30 min 

period 

Ontario Opacity: No. 1 on visible emission chart or 

20% 

Ontario 100 μg PM/m3 At point of impingement; one-half 

hour averaging period 
87

Table 9-2 

Air Quality Standards for Taconite Point Particulate Sources 

Standard 

Emission Limit 

or 

Site-specific Operating Standard Comment 

Quebec 20% opacity Except 40% for < 4 min in 60 min 

period 

Quebec See schedules A and B 

Quebec 50 mg/m3 Material handling operations 
88

Table 9-3 

Air Quality Standards for Taconite Induration Sources 

Standard 

Emission Limit 

or 

Site-specific Operating Standard Comment 

Proposed 40 CFR 

63 Subpart RRRRR 

0.006 gr/dscf From new Straight Grate Indurating 

Furnaces (processing magnetite) 

Proposed 40 CFR 

63 Subpart RRRRR 

0.010 gr/dscf From existing Straight Grate Indurating 

Furnaces (processing magnetite) 

Proposed 40 CFR 

63 Subpart RRRRR 

0.006 gr/dscf From new grate kiln indurating furnaces 

(processing magnetite) 

Proposed 40 CFR 

63 Subpart RRRRR 

0.011 gr/dscf From existing grate kiln indurating 

furnaces (processing magnetite) 

Proposed 40 CFR 

63 Subpart RRRRR 

0.018 gr/dscf From new grate kiln indurating furnaces 

(processing hematite) 

Proposed 40 CFR 

63 Subpart RRRRR 

0.025 gr/dscf From existing grate kiln indurating 

furnaces (processing hematite) 

Minn. R. 7007.0800 Operate all pollution control equipment 

whenever the corresponding process 

equipment is operated 

Minn. R. 7007.0800  Install monitoring equipment for air pollution 

control devices within 180 days of permit 

issuance 

 Complete monitoring equipment debugging, 

troubleshooting, and establishment of 

parameter ranges within 180 days of 

installation or of completion of needed 

repairs of all monitoring equipment 

 Annually calibrate all required monitoring 

equipment 

Minn. R. 7007.0800 Limit fuel use to natural gas and distillate oil 
89

Table 9-3 

Air Quality Standards for Taconite Induration Sources 

Standard 

Emission Limit 

or 

Site-specific Operating Standard Comment 

Minn. R. 7007.0800 Limit fuel use to pulverized coal, coal/coke 

blend, distillate oil, and natural gas 

Minn. R. 7007.0800  Collect a solid fuel sample each weekday 

from the pulverized fuel pipe 

 Form a weekly composite of all samples 

collected in a given calendar week 

 Analyze the weekly fuel composite samples 

for sulfur content in weight percent and 

heating value in Btu/lb 

Minn. R. 7007.0800 Combust only natural gas, all grades of fuel oil, 

and used oil in these emission units 

Minn. R. 7007.0800 If the average total NOx emission rate exceeds 

95% of the NOx emission limit in any 12-month 

period, submit a plan for Agency review and 

approval to implement further monitoring that is 

technically and economically feasible based on 

current technologies. This monitoring could 

include CEMS or PEMS 

Minn. R. 7007.0800 Combust only natural gas, step-specific 

biomass, and/or fuel oil 

Minn. R. 7011.0610 20% opacity or PM process weight rate in 

7011.0700-0735 

Minn. R. 7011.0610 4 lb SO2/MMBtu for solid fuels, 2 lb SO2/MMBtu 

for liquid fuels 

Applies if the total facility-wide rated 

heat input of all indirect and direct 

heating equipment is greater than 250 

MMBtu/hr 

MI R 336.1301 20% opacity 6-minute average 

MI R 336.1331 0.20 lb PM/1,000 lb gas Grate kilns and traveling grates with a 

gas flow rate 0-100,000 scfm 

MI R 336.1331 0.15 lb PM/1,000 lb gas Grate kilns and traveling grates with a 

gas flow rate 100,000-300,000 scfm 

MI R 336.1331 0.10 lb PM/1,000 lb gas Grate kilns and traveling grates with a 

gas flow rate 300,000-600,000 scfm 

MI R 336.1331 Apply to MDEQ for specific emission limit Grate kilns and traveling grates with a 

gas flow rate > 600,000 scfm 
90

Table 9-3 

Air Quality Standards for Taconite Induration Sources 

Standard 

Emission Limit 

or 

Site-specific Operating Standard Comment 

MI R 336.1331 PM: process weight rate 

MI R 336.1402 1.7 lb SO2/MMBtu oil 

MI R 336.1402 2.4 lb SO2/MMBtu coal 

MI R 336.1702 Permitted VOC limit for any existing 

source 

MI R 336.1702 VOC from any new source must be 

less than lowest maximum allowable 

emission rate of the following: 

(a) rate listed by MDEQ on its own 

initiative or based upon the application 

of the BACT 

(b) rate specified by a NSPS 

(c) rate specified in a permit 

MI R 336.1801 Submit a proposal for NOx Fossil fuel-fired emission unit > 250 

MMBtu/hr with a PTE > 25 tons NOx 

for each ozone control period 

Newfoundland 

957/96 

Opacity: No. 1 on visible emission chart Except: 

 No. 2 for < 4 min in 30 min period 

 No. 3 where a new fire is started in 

combustion process 

Ontario Opacity: No. 1 on visible emission chart or 20% Except No. 2, or 40%, for < 4 min in 30 

min period from sources combusting 

solid fuel 

Ontario 100 μg PM/m3 At point of impingement; one-half hour 

averaging period 

Ontario 830 μg SO2/m3 At point of impingement; one-half hour 

averaging period 

Ontario 500 μg NOx/m3 At point of impingement; one-half hour 

averaging period 

Ontario 3,600 μg ammonia/m3 At point of impingement; one-half hour 

averaging period 
91

Table 9-3 

Air Quality Standards for Taconite Induration Sources 

Standard 

Emission Limit 

or 

Site-specific Operating Standard Comment 

Ontario 200 μg ozone/m3 At point of impingement; one-half hour 

averaging period 

Ontario 8,000 μg dustfall/m2 At point of impingement; one-half hour 

averaging period 

Quebec 20% opacity Except: 

 40% for < 4 min in 60 min period 

 60% for < 4 min if starting a fire or 

soot blowing 

Quebec 15 kg VOC/day 

3 kg VOC/hr 

Where photochemically reactive 

organic compounds are not submitted 

to a baking process or do not come in 

contact with a flame 

Quebec 1,400 kg VOC/day 

200 kg VOC/hr 

Where non-photochemically reactive 

solvents are not submitted to a baking 

process or do not come in contact with 

a flame 

Quebec 60 mg PM/MJ New fossil fuel burning equipment 3-15 

MW burning gas or oil, or new fossil 

fuel burning equipment 3-70 MW 

burning coal 

Quebec 85 mg PM/MJ Existing fossil fuel burning equipment 

3-15 MW burning gas or oil, or existing 

fossil fuel burning equipment 3-70 MW 

burning coal 

Quebec 45 mg PM/MJ New fossil fuel burning equipment >15 

MW burning gas or oil, or new fossil 

fuel burning equipment >70 MW 

burning coal 

Quebec 60 mg PM/MJ Existing fossil fuel burning equipment 

>15 MW burning gas or oil, or existing 

fossil fuel burning equipment >70 MW 

burning coal 

Quebec 500 ppm NOx (coal), 250 ppm NOx (oil), 200 

ppm NOx (gas) 

New fuel burning equipment >70 MW 

Quebec 450 ppm NOx (coal), 325 ppm NOx (oil), 150 

ppm NOx (gas) 

New fuel burning equipment 15-70 MW 
92

Table 9-3 

Air Quality Standards for Taconite Induration Sources 

Standard 

Emission Limit 

or 

Site-specific Operating Standard Comment 

Quebec 2.0 wt % sulfur content for heavy oil and coal, 

1.0 wt % sulfur content for intermediate oil, 

0.5 wt % sulfur content for light oil 

Liquid and solid fossil fuel combustion 

units 

Quebec 0.10 kg PM/ton of pellets produced New plant of any capacity 

Quebec 0.36 kg PM/ton of pellets produced Existing plant with production < 

1,500,000 tons of iron oxide pellets/yr 

Quebec 0.12 kg PM/ton of pellets produced Existing plant with capacity >/= 

1,500,000 tons of iron oxide pellets/yr 

9.1 Federal Standards of Performance for Metallic Mineral 

Processing Plants 

The information provided in this section is based on 40 CFR Part 60 Subpart LL. 

9.1.1 Applicability 

A metallic mineral processing plant is any combination of equipment that produces metallic 

mineral concentrates from ore. Metallic mineral processing begins with the mining of ore and 

includes all operations up to and including either: (1) the loading of wet or dry concentrates or 

solutions of metallic minerals for transfer to facilities that will subsequently process the metallic 

concentrates; or (2) all material transfer and storage operations that precede the operations that 

produce refined metals (or other products) from metallic mineral concentrates at facilities 

adjacent to the metallic mineral processing plant. 

Subpart LL applies to the following sources in metallic mineral processing plants: 

• Each crusher and screen in open-pit mines;23

• Each crusher, screen, bucket elevator, conveyor belt transfer point,24 thermal dryer, 

product packaging station, storage bin, enclosed storage area, truck loading station, truck 

unloading station, railcar loading station, and railcar unloading station at the mill or 

concentrator. 

 

23 All sources located in underground mines are exempted from the provisions of this subpart. 24 “Conveyor belt transfer point” excludes by definition any process that transfers the metallic mineral from a 

conveyor to a stockpile. 
93

The NSPS covers some of the sources that are identified and contained in the fugitive and point 

PM source categories in Section 5.8.2. Other PM emission sources that are normally found in 

taconite manufacturing processes and that are not addressed by this NSPS include the following: 

• Non-metallic mineral concentrate handling and storage, such as binders (e.g., bentonite), 

fluxing agents, and other additives 

• Solid fuel (e.g., coal and petroleum coke) handling and storage 

• Vehicular traffic 

Sources that commence construction or modification after August 24, 1982, are subject to the 

requirements of this subpart. It is possible for a source to be both BART-eligible and subject to 

NSPS if it was in place between August 7, 1962 and August 7, 1977 and was either modified or 

reconstructed under NSPS after August 24, 1982. Based on a cursory review of the MPCA 

BART Survey results and current air permits for the taconite plants, some PM emission sources 

are both BART-eligible and subject to NSPS subpart LL. 

9.1.2 Particulate Matter Standards 

Emissions from PM point sources must not: 

1. Contain PM in excess of 0.05 grams per dry standard cubic meter (0.02 grains per dry 

standard cubic foot), or 

2. Exhibit greater than 7% opacity, unless a wet scrubber is used. 

In addition, emissions from PM fugitive sources must not exhibit greater than 10% opacity. 

9.1.3 Compliance Testing and Monitoring 

A facility must conduct an initial performance test of a wet scrubber to measure both the change 

in pressure of the gas stream across the scrubber and the scrubbing liquid flow rate. Facility air 

permits contain additional monitoring requirements to meet the NSPS limits, including: 

• Daily visible emissions checks, 

• Daily or weekly gas stream pressure drop monitoring, and 

• Daily or weekly liquid flow rate monitoring. 
94

9.2 Federal Standards of Performance for Coal Preparation Plants, 

NSPS Subpart Y 

The information provided in this section is based on 40 CFR Part 60 Subpart Y. This subpart 

applies to sources in coal preparation plants that commence construction or modification after 

October 24, 1974 and process more than 200 tons per day, including coal processing and 

conveying equipment (including breakers and crushers), coal storage systems, and coal transfer 

and loading systems. A coal preparation plant is any facility (excluding underground mining 

operations) which prepares coal by one or more of the following processes: breaking, crushing, 

screening, wet or dry cleaning, and thermal drying. Some taconite facilities that use coal as a fuel 

source may not be subject to this regulation if they: 1) do not prepare coal per the definition of a 

coal preparation plant, 2) have facilities that are grandfathered from the rule, or 3) process no 

more than 200 tons per day. Because coal handling activities will likely be addressed for BART 

purposes by other organizations representing coal-fired utilities, a detailed analysis for 40 CFR 

60 Subpart Y has not been performed. 

9.3 National Emission Standards for Hazardous Air Pollutants for 

Taconite Iron Ore Processing 

The information provided in this section is based on the final NESHAPs rule in 40 CFR Part 63 

Subpart RRRRR that was signed on August 25, 2003, but as of the date of this report had not 

been published in the Federal Register. 

9.3.1 Affected Sources 

The proposed rule would currently affect all eight taconite iron ore processing plants in the 

United States. The affected sources within each plant include all new and existing ore crushing 

and handling equipment, ore dryers, indurating furnaces, and finished pellet handling. An 

existing affected source is one constructed or reconstructed on or before December 18, 2002; a 

new affected source is one constructed or reconstructed after December 18, 2002. 

Unlike an NSPS, there is no grandfathering provision to exclude existing equipment from the 

NESHAPs. Therefore, it is possible for a source to be both BART-eligible and subject to 

NESHAPs if it was in place between August 7, 1962 and August 7, 1977. 

9.3.2 Emission Limits and Work Practice Standards 

The proposed rule includes PM emission limits, work practice standards, and operating limits for 

control devices. 

PM serves as a surrogate measure of metallic HAP emissions. The proposed PM emissions limits 

for affected sources are listed in Table 9-4. 
95

Table 9-4 

PM Emission Limits under the Proposed NESHAPs 

Source 

Proposed PM Emissions Limit 

for Existing Sources 

(gr/dscf) 

Proposed PM Emissions Limit 

for New Sources 

(gr/dscf) 

Ore Crushing and Handling 0.008 0.005 

Finished Pellet Handling 0.008 0.005 

Ore Dryer 0.052 0.025 

Straight Grate Indurating 

Furnace (processing 

magnetite) 

0.01 0.006 

Grate Kiln Indurating 

Furnace (processing 

magnetite) 

0.01 0.006 

Grate Kiln Indurating 

Furnace (processing 

hematite) 

0.03 0.018 

The final rule also includes specific requirements for continuous parameter monitoring and 

associated operating limits for baghouses, wet scrubbers, and dry ESP, described in Table 9-5 

below. 

Table 9-5 

Continuous Parameter Monitoring and Associated Operating Limits

Control Device Continuous Parameter Monitoring and Associated Operating Limits 

Baghouse Equip with a bag leak detection system (BLDS) capable of monitoring relative changes in 

PM loading in the baghouse exhaust, which is to alarm whenever a predetermined set 

point is exceeded, indicating an increase in emissions above that allowed at the set point. 

Initiate corrective actions within one hour of an alarm. 

Wet Scrubber For dynamic wet scrubbers, monitor scrubber water flow rate and either the fan amperage 

or pressure drop and operate at all times at or above specified daily average values 

established during initial performance test. For other wet scrubbers, monitor scrubber 

water flow rate and pressure drop and operate at all times at or above specified daily 

average values established during initial performance test. 

Dry ESP Operate continuous opacity monitoring systems (COMS) or maintain daily average 

secondary voltage and daily average secondary current for each field at or above minimum 

levels established during the initial performance test 

The final rule would require sources to submit information on alternative monitoring parameters 

and operating limits if a control device other than a baghouse, wet scrubber, or dry ESP is used. 
96

All plants subject to the rule would be required to prepare and implement a written fugitive dust 

emissions control plan. The plan would describe the measures that will be put in place to control 

fugitive dust emissions from the following sources at a plant: stockpiles, material transfer points, 

plant roadways, tailings basin, pellet loading areas, and yard areas. Existing fugitive dust 

emission control plans that describe current measures to control fugitive dust emission sources 

that have been approved as part of a SIP or Title V permit would be acceptable, provided they 

address the fugitive dust emission sources listed above. 

The NESHAPs for taconite iron ore processing will establish stringent controls on the induration 

point sources as well as most of the fugitive and point particulate sources. The limits for existing 

sources would very likely satisfy BART, since these limits are based on the average emission 

limitation achieved by the best performing five sources, as required in Section 112(d)(3)(B) of 

the CAA. 

9.3.3 Operation and Maintenance 

All plants subject to the proposed rule would be required to prepare and implement a written 

startup, shutdown, and malfunction plan. In addition, a written operation and maintenance plan 

would also be required for each control device subject to an operating limit. 

9.3.4 Initial Compliance Testing 

To demonstrate initial compliance with the PM emission limit for the ore crushing and handling 

and the finished pellet handling sources, the flow-weighted mean concentration of PM emissions 

of all units within the affected source must not exceed the applicable PM emission limit. Initial 

compliance must be demonstrated through a performance test, which must be completed no later 

than 18 months following the effective compliance date. To demonstrate initial compliance with 

the PM emission limit for each indurating furnace and each ore dryer, the flow-weighted mean 

concentration of PM emissions of all stacks for each furnace or each ore dryer must not exceed 

the applicable PM emission limit. Initial compliance must be demonstrated through a 

performance test. 

The final rule will also require that certain operating limits on control devices be established 

during the initial compliance test to ensure that control devices operate properly on a continuing 

basis. All operating limits would be established during a performance test that demonstrates 

compliance with the applicable emission limit. 

To demonstrate initial compliance with the work practice standards, plants would prepare, 

submit, and implement a fugitive dust emission control plan on or before the applicable 

compliance date of the rule. To demonstrate initial compliance with the operation and 

maintenance requirements, plants would certify in their notification of compliance status that 

they have prepared the written plans and will operate control devices according to the procedures 

in the plan. 
97

9.3.5 Continuous Compliance 

For ore crushing and handling, ore dryers and finished pellet handling units, the rule will require 

plants to conduct subsequent performance tests to demonstrate continued compliance with the 

PM emission limits following the schedule established in the Title V permit for each plant. For 

each induration furnace, the rule requires subsequent testing of all stacks based on the schedule 

established in each plant’s Title V operating permit, but no less frequently than twice per fiveyear permit term. 

Plants are required to monitor operating parameters for control devices subject to operating 

limits and carry out the procedures in their fugitive dust emissions control plan and their 

operation and maintenance plan. To demonstrate continuous compliance, plants must keep 

records documenting compliance with the rule requirements for monitoring, the fugitive dust 

emissions control plan, the operation and maintenance plan, and installation, operation, and 

maintenance of a continuous parameter monitoring system (CPMS). To demonstrate continuous 

compliance for baghouses, the rule will require records of bag leak detection system alarms and 

records documenting conformance with the operation and maintenance plan, as well as the 

inspection and maintenance procedures. To demonstrate continuous compliance for scrubbers, 

plants would keep records documenting conformance with the monitoring requirements and the 

installation, operation, and maintenance requirements for the CPMS. To demonstrate continuous 

compliance for dry ESPs, plants must operate and maintain the COMS. 

9.3.6 Compliance Deadlines 

Existing affected sources must comply within 3 years after publication of the final rule in the 

Federal Register. New or reconstructed sources that startup on or before the effective date of the 

final rule must comply by the effective date of the final rule. New or reconstructed sources that 

startup after the effective date of the final rule must comply upon initial startup. 

9.4 Minnesota Rules, Chapter 7011, Standards for Stationary 

Sources 

The information provided in this section is based on Minn. R. Chapter 7011, and addresses 

specifically standards of performance applicable to taconite facilities in Minnesota, as 

summarized in Table 9-6. 
98

Table 9-6 

Minnesota Standards for Stationary Sources Relevant to Standards of Performance at Taconite Plants 

Chapter/Part 

No. Part Description 

Potentially Affected 

Taconite Emission Unit 

Category 

7011.0150 Preventing Particulate Matter from Becoming Airborne Fugitive Particulate Sources 

7011.0610 Standards of Performance for Fossil Fuel-Burning Direct Heating 

Equipment 

Induration Sources 

7011.0710 Standards of Performance for Pre-1969 Industrial Process 

Equipment 

Particulate Point Sources 

Induration Sources 

(pre-July 9, 1969) 

7011.0715 Standards of Performance for Post-1969 Industrial Process 

Equipment 

Particulate Point Sources 

Induration Sources 

(post-July 9, 1969) 

7011.1150 Standards of Performance for New Coal Preparation Plants Fugitive Particulate Sources 

Particulate Point Sources 

7011.2700 Standards of Performance for New Metallic Mineral Processing 

Plants 

Fugitive Particulate Sources 

Particulate Point Sources 

These relevant parts of chapter 7011 of the Minnesota rules are summarized below. See 

Attachment N for full text of these rules. 

9.4.1 Minn. R. 7011.0150 – Preventing Particulate Matter from Becoming 

Airborne 

This part prohibits the handling, use, transporting, or storage of any material in a manner which 

may allow avoidable amounts of particulate matter to become airborne. 

9.4.2 Standards of Performance for Fossil Fuel-Burning Direct Heating 

Equipment 

Minn. R. 7011.0610 prohibits direct heating equipment to discharge any gases which: contain 

particulate matter in excess of the limits allowed by parts 7011.0700 to 7011.0735; or exhibit 

greater than 20% opacity; or contain sulfur dioxide in excess of 4 lb/MMBtu if a solid fossil fuel 

is burned or 2 lb/MMBtu if a liquid fossil fuel is burned, if the total rated heat input of all 

indirect and direct heating equipment of the owner or operator at that particular location exceeds 

250 MMBtu/hr and the direct heating equipment is located outside the Minneapolis-Saint Paul 

Air Quality Control Region. This rule applies to induration sources at the taconite plants. 
99

9.4.3 Standards of Performance for Pre-1969 Industrial Process 

Equipment 

Minn. R. 7011.0710 prohibits industrial process equipment which was in operation before July 9, 

1969 to discharge any gases which: in any one hour contain particulate matter in excess of the 

amount in part 7011.0730 for the allocated process weight, provided that the facility is not 

required to reduce the particulate matter emission below the concentration permitted in part 

7011.0735 for the appropriate source gas volume or that regardless of the mass emission 

permitted by part 7011.0730 the facility is not permitted to emit particulate matter in a 

concentration in excess of 0.30 gr/scf of exhaust gas; or exhibit greater than 20% opacity. Such a 

facility located outside the Minneapolis-Saint Paul Air Quality Control Region and the city of 

Duluth which has control equipment with a collection efficiency of not less than 85% by weight 

and does not cause a violation of the ambient air quality standards is considered in compliance 

with the requirements above. 

9.4.4 Standards of Performance for Post-1969 Industrial Process 

Equipment 

Minn. R. 7011.0715 prohibits industrial process equipment which was in operation after July 9, 

1969 to discharge any gases which: in any one hour contain particulate matter in excess of the 

amount in part 7011.0730 for the allocated process weight, provided that the facility is not 

required to reduce the particulate matter emission below the concentration permitted in part 

7011.0735 for the appropriate source gas volume or that regardless of the mass emission 

permitted by part 7011.0730 the facility is not permitted to emit particulate matter in a 

concentration in excess of 0.30 gr/scf of exhaust gas; or exhibit greater than 20% opacity. Such a 

facility located outside the Minneapolis-Saint Paul Air Quality Control Region and the city of 

Duluth which has control equipment with a collection efficiency of not less than 85% by weight 

and does not cause a violation of the ambient air quality standards is considered in compliance 

with the requirements above. 

9.4.5 Standards of Performance for New Coal Preparation Plants 

Minn. R. 7011.1150 incorporates 40 CFR part 60 subpart Y, Standards of Performance for Coal 

Preparation Plants, by reference (summarized in Section 9.2). 

9.4.6 Standards of Performance for New Metallic Mineral Processing 

Plants 

Minn. R. 7011.2700 incorporates 40 CFR part 60 subpart LL, Standards of Performance for 

Metallic Mineral Processing Plants, by reference (summarized in Section 9.1). 

9.5 Michigan Air Pollution Control Rules 

Michigan Department of Environmental Quality (MDEQ) air pollution control (APC) rules were 

reviewed for relevance to the emission limits at two taconite ore processing facilities located in 
100

the state. It was determined that four parts apply to taconite facilities for purposes of BART, as 

shown in Table 9-7. 

Table 9-7 

MDEQ APC Rules Relevant to Standards of Performance at Taconite Plants

Part 

No. Part Description 

Potentially Affected Taconite 

Emission Unit Category 

3 Emission Limitations And Prohibitions - Particulate Matter Fugitive Particulate Sources 

Point Particulate Sources 

Induration Sources 

4 Emission Limitations And Prohibitions - Sulfur-Bearing Compounds Induration Sources 

7 Emission Limitations And Prohibitions - New Sources Of Volatile 

Organic Compound Emissions 

Induration Sources 

8 Emission Limitations And Prohibitions - Oxides Of Nitrogen Induration Sources 

These four relevant parts of the Michigan rules are summarized below. See Attachment O for full 

text of these rules. 

9.5.1 Part 3 – Particulate Matter Emission Limitations and Prohibitions 

9.5.1.1 R 336.1301 – Standards for density of emissions 

This rule prohibits process equipment from exceeding an opacity greater than the most stringent 

of the following: (a) a 6-minute average of 20%, (b) a limit specified by an applicable federal 

new source performance standard, (c) a limit specified as a condition of a permit to install or 

operate. 

9.5.1.2 R 336.1331 – Emission of particulate matter 

This rule identifies maximum allowable emission rates of PM from process equipment. It 

includes rates for grate kilns and traveling grates as shown in Table 9-8. 

Table 9-8 

Maximum Allowable PM Emission Rates for Grate Kilns and Traveling Grates

Process or process 

equipment 

Gas flow rate 

(SCFM) 

Maximum allowable emission at operating 

conditions1

(lbs. Particulate/1,000 lbs. gas) 

Applicable 

reference test 

method 

Iron ore pelletizing

Grate kilns and traveling 

grates 

Over 600,000 

300,000-600,000 

100,000-300,000 

0-100,000 

Apply to department for specific emission limit. 

0.10 

0.15 

0.20 

5B or 5C 

5B or 5C 

5B or 5C 
101

The rule also identifies the allowable PM emission rate from process equipment based on process 

weight rate. 

9.5.1.3 R 336.1370 – Collected air contaminants 

This rule requires that air contaminants be removed as necessary to maintain the equipment at 

the required operating efficiency. This rule also specifies material handling methods required for 

transporting air contaminants. 

9.5.1.4 R 336.1371 – Fugitive dust control programs other than areas listed in table 36 

This rule requires a facility that processes, uses, stores, transports, or conveys bulk materials, 

such as metal ores, from air pollution control devices to submit a fugitive dust control program. 

The rule contains the fugitive dust control program requirements. 

9.5.1.5 R 336.1372 – Fugitive dust control program; required activities; typical control methods 

This rule identifies the provisions that apply to the loading or unloading of open storage piles of 

bulk materials, transporting of bulk materials, outdoor conveying, roads and lots, inactive storage 

piles, and building ventilation as a source of fugitive dust. 

9.5.2 Part 4 – Sulfur-Bearing Compounds Emission Limitations and 

Prohibitions 

9.5.2.1 R 336.1402 - Emission of sulfur dioxide from fuel-burning sources other than power 

plants 

This rule prohibits the emission of sulfur dioxide from the combustion of any coal or oil fuel in 

excess of 1.7 lb/MMBtu for oil fuel or in excess of 2.4 lb/MMBtu for coal fuel. 

9.5.3 Part 7 – New Sources of VOC Emissions – Limitations and 

Prohibitions 

9.5.3.1 R 336.1702 – New sources of volatile organic compound emissions generally 

This rule prohibits the emission of volatile organic compounds from any new source in excess of 

the lowest maximum allowable emission rate of the following: 

a. The maximum allowable emission rate listed by the department on its own initiative or based 

upon the application of the BACT. 

b. The maximum allowable emission rate specified by a federal new source performance 

standard. 

c. The maximum allowable emission rate specified in a permit. 
102

9.5.4 Part 8 – Emission Limitations and Prohibitions - Oxides of Nitrogen 

9.5.4.1 R 336.1801 – Emission of oxides of nitrogen from non-SIP call stationary sources 

This rule requires fossil fuel-fired emission units with a PTE of more than 25 tons of NOx for 

each ozone control period that is greater than 250 MMBtu/hr to submit a proposal for NOx 

control. It contains the proposal requirements and means by which NOx emissions must be 

measured. The rule also allows an affected source to participate in Michigan’s emission trading 

program. 

9.6 Summary of Canadian Provincial Air Pollution Control 

Regulations 

Taconite plants are located in three Canadian provinces, Newfoundland, Ontario, and Quebec,25

so only the air pollution control regulations in these three provinces have been reviewed. The 

relevant Canadian provincial rule parts are summarized below. See Attachment P for full text of 

these rules. 

9.6.1 Newfoundland Air Pollution Control Regulations 

The standards of performance in the Newfoundland air pollution control regulations that are 

potentially applicable to taconite plants include an air contaminant standard for any point source 

and a visible emissions standard.26

9.6.1.1 Stationary source of air contamination 

The maximum concentration of a contaminant at a point of impingement from a source must not 

be greater than the concentration described in Table 9-9. 

 

25 Canadian Minerals Yearbook, 1995; chapter 32, “Iron Ore and Primary Iron.” 

26 Based on “Consolidated Newfoundland Regulation 957/96” found at http://www.gov.nf.ca/hoa/sr/, as of April 

2003. 
103

Table 9-9 

Maximum Concentration of a Contaminant at a Point of Impingement

Contaminant 1 hour averaging period 

SO2 680 ug/m3

NOx 400 ug/m3

PM 80 ug/m3

Ammonia 3,000 ug/m3

Ozone 160 ug/m3

Dustfall 7,000 ug/m2

9.6.1.2 Visible emission standards 

Opacity must not exceed density No. 1 on the visible emission chart, except: 

a. For a period of not more than 4 minutes in the aggregate in a half hour period, visible 

emission may have an opacity exceeding density No. 1 but not exceeding density No. 2; 

b. Where a new fire is started in combustion process equipment, the visible emission may have 

an opacity not exceeding density No. 3 for a period not more than 3 minutes in the aggregate 

in a quarter hour period up to one hour after the new fire is started. 

The visible emission chart is based on the Ringelmann scale for determining opacity.27

9.6.1.3 Recording devices 

The minister may require the installation of devices or methods that are necessary to: 

a. Record the periods of operation of process, combustion or control equipment, the records 

from which shall be available to a department official. 

b. Measure and record concentrations of air contaminants at their source and points of 

impingement, the records and measurements from which shall be available to a department 

official. 

9.6.2 Ontario Air Pollution Control Regulations 

The standards of performance in the Ontario air pollution control regulations that are potentially 

applicable to taconite plants include an air contaminant standard for any point source and a 

visible emissions standard.28

 

27 See Schedule C of c. Q-2, r. 20, Regulation respecting the quality of the atmosphere, found at 

www.publicationsduquebec.gouv.qc.ca/home.php, as of April 2003. 28 Based on “Environmental Protection Act, R.S.O. 1990, c. E.19” found at http://www.e-laws.gov.on.ca/, as of 

April 2003. 
104

9.6.2.1 Control of air contaminants 

The maximum concentration of a contaminant at a point of impingement from a source must not 

be greater than the concentration described in Table 9-10 below: 

Table 9-10 

Maximum Concentration of a Contaminant at a Point of Impingement

Contaminant 1⁄2 hour averaging period 

SO2 830 ug/m3

NOx 500 ug/m3

PM 100 ug/m3

Ammonia 3,600 ug/m3

Ozone 200 ug/m3

Dustfall 8,000 ug/m2

Visible emissions must not have shades of grey darker than No. 1 on the Visible Emission Chart 

of the Province of Ontario or obstruct the passage of light to a degree greater than 20% at the 

point of emission. A visible emission from a source of combustion using solid fuel for a period 

of not more than four minutes in the aggregate in any 30-minute period may be in shades of grey 

darker than No. 1, but not darker than No. 2 on the Visible Emission Chart or obstruct the 

passage of light to a degree greater than 20% but no greater than 40% at the point of emission. 

A facility must not construct, alter, demolish, drill, blast, crush or screen anything so that a 

contaminant is carried beyond the limits of the property on which the operation is being carried 

out or sandblast anything so that a contaminant is emitted into the air to an extent or degree 

greater than that which would result if every step necessary to control the emission of the 

contaminant were implemented. 

9.6.3 Quebec Air Pollution Control Regulations 

The standards of performance in the Quebec air pollution control regulations29 that are 

potentially applicable to taconite plants include: 

• a visible emissions standard, 

• a VOC standard, 

• a fugitive emissions standard, 

• a particulate matter standard, 

• a fossil fuel use standard, and 

 

29 Based on “Regulation respecting the quality of the atmosphere, c. Q-2, r. 20” found at 

http://www.publicationsduquebec.gouv.qc.ca/. 
105

• an iron ore pelletizing plant PM standard. 

9.6.3.1 Opacity of emissions 

The concentration of contaminants discharged by a stationary source must not exceed 20% 

opacity. This does not apply to the starting of a fire or the soot blowing. The degree of opacity 

may then, for a maximum period of 4 consecutive minutes exceed 20% but never be equal to or 

higher than 60% opacity. During the operation of a stationary source, the degree of opacity of an 

emission may also exceed 20% for one or several periods not exceeding 4 minutes in any one 

hour, but never be equal to or higher than 40%. 

9.6.3.2 Emission of organic compounds 

A facility may not emit into the atmosphere: 

a. more than 15 kilograms per day and 3 kilograms per hour of organic compounds for 

photochemically reactive organic compounds which are not submitted to a baking process or 

do not come in contact with a flame; 

b. more than 1,400 kilograms per day or 200 kilograms per hour of organic compounds where 

non-photochemically reactive solvents are not submitted to a baking process or do not come 

in contact with a flame. 

For the purposes of enforcing this section, the different portions of a continuing process 

constitute only one stationary source. Organic compound emissions mentioned in (b) and (c) 

comprise all emissions produced during the 12 hours used for drying, following the last 

application of organic solvents or substances which contain them. 

Organic compound emissions may exceed the standards above provided that there is a reduction 

of the emissions in the atmosphere of at least 90% for incineration of organic compounds and at 

least 85 % in other cases. 

9.6.3.3 Fugitive emissions 

A facility which wrecks, builds, repairs or maintains a building or a thoroughfare must spread 

water or another dust control product to prevent the raising of dust in all cases where the carrying 

out of such activity brings about the emission of dust. A facility that produces dust emissions 

from access lanes and road ways located on the same property as a stationary source or a pile of 

aggregates, materials, mine refuse, ore, ore concentrate or pellets must take the necessary 

measures to control these emissions so as to eliminate those effects. This section also applies to 

the transport by conveyor belt, truck, or railway car of the materials mentioned above. 

In the case where the transfer or free fall of materials of any kind including aggregates, mine 

rejects ore, ore concentrate or pellets, brings about the emission of dust which can be seen in the 

atmosphere more than 2 meters away from the emission source, the facility must take the 

necessary measures so that: 
106

a. The stationary transfer point is included in an enclosed space equipped with ducts which 

draw dust to a dust collector so that the PM emissions are not greater than 50 mg/m3

; or 

b. The free fall height of these materials does not exceed 2 meters. 

Dust emissions resulting from dry sandblasting operations must be controlled by using an 

enclosure or screen in order to confine the dust inside the spaces thus enclosed or closed. This 

section also applies to wet-type sandblasting operations when there are dust emissions that can 

be seen in the atmosphere more than 2 meters from the emission source. 

Dust recuperated by a dry collector must be handled and transported so that there is no dust 

released which can be seen 2 meters from the emission source. When it is not recycled, it must 

be stored, spread or disposed of on the ground and the necessary measures must be taken to 

prevent any release of dust which can be seen 2 meters away from the emission source, and in 

order to prevent water contamination. 

9.6.3.4 Particulate matter general emission standards 

A facility must not emit PM in excess of the hourly quantities allowed respectively for existing 

and new stationary sources in Schedules A and B of the standard. PM emissions from any 

transfer of bulk material except wood, any storage in confined environment, any digging other 

than the sinking of a supply water well, any welding operation metal works in indoor 

sandblasting, and any process for the preparation, concentration, agglomeration or drying of ore 

or ore concentrate, as well as to the related handling operations done in a plant for the 

preparation, concentration, agglomeration or drying of metallic ores, must not exceed 50 mg/m3. 

9.6.3.5 Use of fossil fuels 

Fossil fuel burning equipment must not emit PM beyond the standards described in Table 9-11 

below: 

Table 9-11 

PM Emission Limits for Fossil Fuel Burning Equipment

Heat Input Capacity 

of fuel as fired Type of fuel 

New Installation 

(mg/MJ) 

Existing Installation 

(as of 6/1/81) 

(mg/MJ) 

3 – 15 MW gas or oil product 60 85 

3 and 70 MW coal 60 85 

>15 MW gas or oil product 45 60 

>70 MW coal 45 60 

A new fuel burning equipment must not emit NOx beyond the standards described in Table 9-12 

below: 
107

Table 9-12 

NOx Emission Limits for New Fuel Burning Equipment

Heat Input Capacity 

of fuel as fired Type of fuel 

Emission Standard 

(ppm, dry basis to 3% O2) 

>70 MW coal 500 

 oil 250 

 gas 200 

15-70 MW coal 450 

 oil 325 

 gas 150 

A facility must not burn fuel with a sulfur content higher than: 

a. 2.0 % in weight for heavy oil; 

b. 1.0 % in weight for intermediate oil; 

c. 0.5 % in weight for light oil; and 

d. 2.0 % in weight for coal. 

The standards above for heavy oil and coal do not apply in cases where: 

a. a portion of the sulfur contained in the flue gases is recovered and combined to a raw 

material coming in contact with these gases; 

b. a portion of the sulfur contained in the flue gases is retained by a gas cleaning equipment; or 

c. another fossil fuel with a low sulfur content is used simultaneously in an oil refinery. 

Except as provided in the paragraph above, the quantity of SO2 emitted by burning any fossil fuel 

must not exceed that emitted by burning a quantity equivalent in heating value of heavy oil 

whose sulfur content does not exceed the standards described above. 

 

The exhaust speed of flue gases from a new fuel burning equipment fired with heavy oil or coal 

must be at least 15 meters per second at the outlet of a new stack when the equipment operates at 

nominal capacity. 

 

The minimum height of any new stack of a fuel burning equipment using heavy oil or coal must 

be equal at least to the one computed in conformity with the method entitled Méthode de calcul 

de la hauteur minimale des cheminées published in 1979 by the Services de protection de 

l'environnement. The height of an existing stack cannot be reduced unless it still is, after 

reduction, in conformity with the height computed according to the method provided for above. 

9.6.3.6 Iron ore pelletizing plants 

The indurating process of an iron ore pelletizing plant must not emit PM in excess of that 

described in Table 9-13 below: 
108

Table 9-13 

PM Emission Limits for Induration Processes at an Iron Ore Pelletizing Plant

Type of Plant Standard 

New plant of any capacity 0.10 kg/tonne of pellets produced* 

Existing plant with a nominal yearly production lower 

than 1,500,000 tons of iron oxide pellets 

0.36 kg/tonne of pellets produced* 

Existing plant with a nominal yearly capacity equal to 

or greater than 1,500,000 tons of iron oxide pellets 

0.12 kg/tonne of pellets produced* 

* Including the recirculating load, if applicable. 

9.7 Summary of BACT Determinations 

The information provided in this section is based on two BACT determinations found in EPA’s 

RACT, BACT, LAER Clearinghouse (RBLC) and the Title V operating permits of the taconite 

facilities. The RBLC was queried on April 15, 2003 by taconite facility name. 

One taconite processing facility determined that its indurating machine is subject to a BACT 

limit for NOx. Eleven control options were examined and BACT determined to be limiting fuel 

use to 270 MMBtu/hr for all the burners combined in addition to the use of existing low-NOx 

burners. NOx is limited to 1088 lb/hr. See Attachment Q for a summary of the RBLC report. The 

operating permit for this facility was issued January 14, 2000. 

The MPCA determined for another taconite processing facility that selective catalytic reduction 

(SCR) is not BACT for NOx emission control for its PSD permit. 
109

10 Visibility Impacts Screening Evaluation of the Taconite 

Industry 

Barr has performed a visibility impacts screening evaluation for the purpose of understanding the 

pollutants of concern for visibility from the taconite industry as well as to inform the taconite 

industry on visibility impacts from its emission sources. 

The results of this modeling analysis serve to assess the potential change in visibility due to the 

application of BART at the taconite facilities in Minnesota. Due to the simplifying assumptions 

and streamlined analysis, the visibility impacts screening evaluation, in itself, has limited 

application. As such, the results in Section 10.2 are shown for informational purposes and should 

not be construed to represent a determination of compliance with an applicable requirement. 

10.1 Modeling Protocol 

On August 25, 2003, Barr submitted a memorandum to Ms. Margaret McCourtney and Mr. 

Stuart Arkley at MPCA outlining a protocol to use for the visibility impacts screening 

evaluation. A copy of this memo is in Attachment S. Pursuant to this memorandum and 

subsequent e-mail correspondence between Barr and MPCA, the following model protocol is 

used for the visibility impacts screening evaluation. 

10.1.1 Modeling Program 

The CALMET/CALPUFF/CALPOST system will be used for this analysis. Attachments T, U, 

and V contain an input file an example CALPUFF input file with the proposed control options to 

be used in the analysis. This modeling program is chosen for the following reasons: 1) 

CALPUFF is an EPA-approved model for performing far-field visibility impacts studies at 

Class I areas, and 2) Barr had recently performed a visibility impacts analysis for a potential new 

taconite plant in northern Minnesota. Mr. John Notar of the National Park Service approved in 

general the CALPUFF and CALMET input files before the project was subsequently cancelled. 

These files were used as templates for the modeling analysis. 

Four CALMET input files were created, one for each quarter in the 12-month period between 

December 1, 1984, and November 30, 1985. Six CALPUFF and CALPOST input files were 

created. The CALPUFF executable used for this analysis allows 500 receptors, so three runs for 

needed to capture all 1,313 receptors (see Section 10.1.4) for the pre-BART and post-BART 

emissions scenarios. 

Note that regulatory agencies will likely not use the CALMET/CALPUFF/CALPOST system for 

regional haze modeling. The visibility impact results from other modeling programs may reveal 

conclusions different than those gathered in this analysis using 

CALMET/CALPUFF/CALPOST. 
110

10.1.2 Sources 

Consistent with Table 7-1, four ‘typical’ sources will be modeled: grate/kiln furnace, straight 

grate furnace, pellet cooler, and ore handling. One representative stack will be used for each of 

the sources, for a total of four modeled sources. Table 10-1 contains the stack parameters that 

will be used in the modeling. Flow rate and temperature parameters were taken from Table 7-1. 

The stack height and stack diameter parameters are estimated from taconite source data in the 

MPCA Delta Database. All of the stack parameters represent a typical stack configuration rather 

than a “worst-case” stack. 

The model plant location containing the four sources as well as the location of the existing 

Minnesota taconite plants are shown in Figure 10-1. 

Table 10-1 

Sources and Stack Parameter Data in CALPUFF Input File

English Units 

Height Temperature Flow Diameter 

(ft) (F) (acfm) (ft) 

Straight Grate Furnace 140 135 188,865 8 

Grate/Kiln Furnace 140 135 377,730 13 

Pellet Cooler 135 800 239,425 13 

Ore Handling 80 77 7,143 2 

 

Metric Units 

Height Temperature Velocity Diameter 

Source Type (m) (K) (m/s) (m) 

Straight Grate Furnace 42.7 330 19 2.4 

Grate/Kiln Furnace 42.7 330 14 4.0 

Pellet Cooler 41.1 700 9 4.0 

Ore Handling 24.4 298 12 0.6 

Barr has not modeled fugitive particulate sources for the following reasons: 

• Only one facility included fugitive sources in the BART-eligible survey, indicating that 

most fugitive sources are either not BART-eligible or were specifically excluded in the 

survey. 

• Fugitive emissions tend to be coarse particulates, which in general are not the drivers 

for far-field visibility degradation as compared to sulfates, nitrates, and fine particulate 

matter. 

• All of the taconite facilities have fugitive dust control plans, as described in the draft 

BART report; therefore, BART for fugitive sources would likely not be different from 

what is already in the fugitive dust control plans. 
111

Figure 10-1. Location of Modeled Plant and Class I Area Receptors. 
112

10.1.3 Pollutants and Emission Rates 

CALPUFF allows for the specification of the pollutants to be modeled. Because limited 

information is currently available on the pollutants to be modeled, especially with respect to fine 

particulate matter (e.g., PM2.5) and elemental carbon, we propose to model the emissions of SO2, 

NOx, and coarse particulate matter (PM10), and model the ground-level concentrations of these 

three pollutants plus the formation of nitrates (NO3 and HNO3) and sulfates (SO4). 

For estimated pre-BART emissions from each of the four sources, taconite industry total 

emissions are based on the 2001 emission inventory total in Table 5-1 and divided by a 0.85 

capacity factor, as referenced in a technical paper from Mr. Hongming Jiang of MPCA regarding 

the taconite industry. The scaled-up 2001 industry emission totals are apportioned into the four 

sources as shown in Table 10-2, which reflect emissions from the source categories. One preBART scenario is modeled. 

The post-BART emission rates are equal to the pre-BART emission rates times an estimated 

control efficiency for the selected BART. Some of the BART-eligible sources already have 

controls that would likely meet BART, so the incremental control efficiency dictated by BART 

for the taconite industry will likely be less than that shown for the individual control 

technologies in Table 6-1 of the draft BART report. Barr proposes a 30% emissions reduction in 

pre-BART NOx, SO2, and PM10 emission rates for the post-BART scenario. This is an estimate 

that will help provide an idea of the visibility reduction in relationship to an emissions reduction. 

It should not be construed to be an expected emissions reduction from the taconite industry due 

to application of BART. 

Table 10-2 

Pre-BART and Post-BART Taconite Industry Emission Rates in CALPUFF Input File

Pre-BART Emissions (tons) Post-BART Emissions (tons) 

Source PM10 SO2 NOx PM10 SO2 NOx 

Grate/Kiln 4,595 6,693 21,395 3,217 4,685 14,977 

Straight Grate 358 331 4,396 251 232 3,077 

Pellet Cooler 195 -- -- 137 -- -- 

Ore Handling 1,027 -- -- 719 -- -- 

10.1.4 Receptors 

Discrete receptors are established every 2 kilometers at both Boundary Waters Canoe Area 

Wilderness (BWCAW) and Voyageurs National Park. There are 1,105 receptors for BWCAW 

and 208 receptors for Voyageurs National Park. See Figure 10-1 for identification of the receptor 

locations. 

10.1.5 Model Control Selections 

The model source location of the single plant to be modeled is illustrated as a figure in 

Attachment C. The base elevation for the modeled plant is 475 m, which is the average of the 
113

five plants on the Mesabi range. Building downwash will not be included in the model. Barr 

modeled one year of meteorological data (December 1984 through November 1985). Deposition 

is included in the modeling. Other non-taconite industry sources are not included in the modeling 

in order to gauge the impact of pre-BART to post-BART emissions on visibility. Default 

CALPUFF values for the chemistry parameters are used with the following exceptions that were 

approved in a previous analysis by National Park Service: 

Ozone Background: 40 ppm (default is 80) 

Ammonia Background: 1 ppm (default is 10) 

10.2 Modeling Results 

Table 10-3 summarizes the comparison in visibility impacts between pre-BART and post-BART 

taconite industry emissions. The results in this table reflect the highest percent change in light 

extinction at any of the 1,313 receptors modeled. Figure 10-2 illustrates the day-to-day variation 

in the modeled visibility impact from the taconite industry. In summary, the visibility impacts 

screening evaluation of taconite industry pre-BART and post-BART emissions make known the 

following: 

1. On average, nitrates formed from taconite industry NOx emissions represent approximately 

85 % of the visibility impact at Class I areas, whereas sulfates constitute 9 % and particulate 

matter makes up 6 % of the visibility impact. For comparison purposes, a study on visibility 

impairment by Colorado State University (see Section 7.1.1) found that sulfates contribute 

54 % of the visibility impairment and nitrates contribute 17 % of the visibility impairment in 

the Voyageurs National Park and BWCAW. 

2. As noted in Section 10.1.3, fine particulate matter and elemental carbon emissions have not 

been estimated for this modeling analysis due to the lack of emissions data. In general, fine 

particulate matter and elemental carbon cause significantly higher visibility impacts than 

coarse particulate matter. 

3. Although nitrates contribute the vast majority of the visibility impact, sulfates and coarse 

particulate matter can each cause a noticeable (i.e., greater than 5 %) increase in light 

extinction on certain days as well. 

4. The reduction in visibility impact at the highest receptor on the worst-case day closely 

matches the emissions reduction of 30 % for each pollutant (SO2, NOx, and PM10). 

5. Relative humidity plays an important role in visibility degradation. The higher the relative 

humidity, the greater the visibility impact. However, in Figure 10-1 there seems to be no 

significant seasonal trends. 
114

Table 10-3 

Comparison of Modeling Results Between Pre-BART and Post-BART Taconite Industry Emissions

Number of Days/Year with 

Greater than 0%, 5%, and 10% 

Light Extinction Change* 

Average Contribution by Pollutant 

for those Days With > 5% Change 

Estimated in Light Extinction* 

Potential 

Emissions 

Scenario 

Highest 

Daily % 

Change in 

Light 

Extinction* > 0% 

Change 

> 5% 

Change 

> 10% 

Change 

Sulfates 

(SO4) 

Nitrates 

(NO3) 

Coarse 

Particulate 

Matter (PM) 

Pre-BART 114% 200 Days 148 Days 115 Days 9.4% 84.4% 6.1% 

Post-BART 

(30% less than 

Pre-BART) 

80% 199 Days 125 Days 85 Days 8.9% 85.1% 6.0% 

% Difference 

between Preand Post-BART 

-30% -1% -16% -26% -5% +1% -2% 

* The percent change in light extinction is calculated as the difference in light extinction due to the modeled sources and 

modeled natural background. 
115

Figure 10-2. Daily Change in Light Extinction from Pre-BART and Post-BART Taconite Industr

0

20406080

100120

12/1/84 1/1/85 2/1/85 3/1/85 4/1/85 5/1/85 6/1/85 7/1/85 8/1/85 9/1/85 10/1/8

Change in Light Extinction Compared to Background (%)

Pre-BART Post-BART
116

11 Conclusions 

The 1999 Regional Haze final rule and 2001 proposed BART guidelines lay a regulatory 

framework for states and the regulated community to begin the process of meeting the visibility 

goals in Section 169a of the CAA. However, legal challenges to the BART guidelines and the 

PM2.5 national ambient air quality standards (NAAQS) have delayed implementation of the 

program. 

Minnesota, like all states, is required to submit an implementation plan for Regional Haze. In 

addition to the progress goals and visibility improvement strategies that are required in the 

implementation plan, the MPCA must identify specific BART limitations for units that are 

subject. Based on a survey of BART-eligible units conducted by the MPCA, all six taconite 

plants in Minnesota have BART-eligible units. 

Utilizing the results from MPCA’s BART-eligible unit survey for the taconite plants, Barr has 

classified taconite emission units into three categories: fugitive particulate sources, point 

particulate sources, and induration point sources. The taconite BART screening evaluation 

focuses on control technology options for these three emission unit categories. 

A comprehensive review of Federal, State (Minnesota and Michigan), and Canadian 

(Newfoundland, Ontario, and Quebec) air quality regulations revealed that the three taconite 

emission unit categories are already required to meet existing standards of performance, whether 

these standards are generally applicable state requirements or more stringent emission 

limitations. It should be noted that both Michigan and Quebec have particulate matter emission 

limitations in their regulations that are specific to existing taconite induration furnaces. 

The final NESHAPs for taconite iron ore processing establishes stringent particulate matter 

controls on the induration point sources as well as most of the fugitive and point particulate 

sources. The particulate matter limits for existing sources would very likely satisfy BART, since 

these limits are based on the average emission limitation achieved by the best performing five 

sources, as required in Section 112(d)(3)(B) of the CAA. Since a BART evaluation must take 

into account the level of control already in place, the cost effectiveness of installing BART – on 

top of the existing NESHAPs (or BACT, LAER, or NSPS) levels of control – may be 

restrictively high because baseline annual particulate matter emissions will be very low due to 

the aforementioned existing controls. Uncontrolled emission units that are subject to BART but 

are not already controlled for a visibility impairing pollutant will most likely require a level of 

investment in order to meet BART. 

The anticipated first compliance date for a BART limitation at taconite facilities is December 

2012. Several variables influence the timing, such as the PM2.5 attainment/nonattainment 

designation time frame, MPCA’s Regional Haze implementation plan schedule, and the 

compliance schedule for taconite facilities to meet BART after the implementation plan is 

approved. 

In addition to providing the regulatory context for this analysis, another purpose of this report is 

to conduct a BART screening evaluation for the taconite industry. The approach addresses the 
117

taconite industry in general; site-specific BART analyses are beyond the scope of this analysis. 

This analysis contains information, cost calculations, and model examples that provide for a 

uniform approach in subsequent preparation of site-specific BART analyses. 

Four model sources were chosen and evaluated for the technical feasibility of air pollution 

controls on a pollutant-by-pollutant basis. Several possible control technologies are determined 

to be technically infeasible on an industry-wide basis because of conditions inherent to the 

taconite manufacturing process. The remaining technically feasible options are summarized in 

Table 11-1. 

When site-specific BART analyses are performed, some of the options determined to be feasible 

for the general industry may be found technically infeasible based on site-specific conditions. 

The approach for calculating the cost of controls is demonstrated for the particular model source. 

The affordability of BART must be analyzed on a site-specific basis. Given the current 

economics of the industry, a significant cost burden associated with BART could impact the 

future viability of the industry. 
118

Table 11-1 

Summary of Technically Feasible Control Technologies

Model Source 

Category Pollutant Control Technology 

Control 

Efficiency 

Induration NOx SCR 70% to 90% 

 IFGR Burners 50% 

Low-NOx Burners 25% 

 Ported Kiln > 5% 

 SO2 High Efficiency Wet Scrubber 95% 

Low Efficiency Wet Scrubber 80% 

 WWESP 80% 

 PM Dry ESP 98%-99%+ 

 WWESP 98%-99%+ 

High Efficiency Wet Scrubber 95%-99%+ 

Low Efficiency Wet Scrubber 90%-95% 

 Multiclones 50%-80% 

Pellet Coolers PM Fabric Filters (Baghouses) 98%-99%+ 

 Dry ESP 98%-99%+ 

 WWESP 98%-99%+ 

High Efficiency Wet Scrubber 95%-99%+ 

Low Efficiency Wet Scrubber 90%-95% 

 Multiclones 80%-90% 

Material Handling PM Fabric Filters (Baghouses) 98%-99%+ 

 Dry ESP 98%-99%+ 

 WWESP 98%-99%+ 

Wet Scrubbers High Efficiency 95%-99%+ 

Wet Scrubbers Low Efficiency 90%-95% 

 Multiclones 80%-90% 

 Enclosure 50%-100% 

 Chemical Stabilization 75%-80% 

Wet Suppression 50%-75% 

Best Management Practices Variable 
ATTACHMENT A 

December 9, 2002, State Register 
State Contracts

(CITE 27 SR 849) State Register, Monday 9 December 2002 PAGE 849

Minnesota Historical Society

Request for Bids for Stabilization and Repair of Meighen Residence Frame Addition at

Historic Forestville Preston, Minnesota 

The Minnesota Historical Society seeks bids for stabilization and repair work on the Meighen Residence Frame Addition at

Historic Forestville in Preston, Minnesota. Work includes sill replacement; joist repair/replacement; excavation of crawlspace;

foundation stabilization; restoration of siding to original pattern; restoration/repair of wood frame and sash windows; repair/restoration/replacement of wooden storm windows; sanding/priming/painting exterior; re-installation of existing wood tongue and groove

flooring; lathe and plaster repair; draining and filling cistern; and realignment/installation of gutter system. Also included are miscellaneous repairs on attached brick structures including painting windows and tuck-pointing. All work must conform to the

Secretary of the Interior’s Standards for Historic Preservation.

A MANDATORY pre-bid meeting will be held Wednesday, December 18, 2002, at 11:00 a.m. at Historic Forestville. Copies of

the bidding documents may be obtained from Collaborative Design Group, inc., 1501 Washington Avenue South, Suite 300,

Minneapolis, Minnesota, 55454.

The deadline for receipt of bids is Tuesday, January 7, 2003, 2:00 p.m. Late bids will not be accepted. Bids should be sent or

delivered to: Chris M. Bonnell, Contracting Officer, Minnesota Historical Society, 345 Kellogg Boulevard West, St. Paul,

Minnesota 55102. Clearly mark the project name “Meighen Residence Frame Addition, Historic Forestville” on the outside of the

package.

Dated: 9 December 2002

Minnesota Pollution Control Agency

Notice of Availability of Contract for Assessment of Impact of Regional Haze Rules on the

Taconite Industry

The Minnesota Pollution Control Agency (MPCA) is requesting proposals for the purpose of surveying and reporting on the

potential impacts of the federal regional haze rule on the taconite industry in Minnesota. This rule requires certain sources to

conduct an initial analysis which may lead to a more detailed assessment and installation of emissions controls that conform to Best

Available Retrofit Technology (BART) requirements. The taconite industry has been identified by the MPCA as one of the industries for which a BART analysis is required. This project will provide a general analysis for the industry as a whole that can be used

by both the MPCA and the taconite industry itself as a basis for planning purposes and for any facility-specific detailed assessments

that will follow.

Work is proposed to start after February 1, 2003.

Call or write for a copy of the full Request for Proposal document, which will be sent free of charge to interested vendors. The

full Request for Proposal can be obtained from:

Stuart Arkley, Project Manager

Policy and Planning Division

Minnesota Pollution Control Agency

520 Lafayette Road

St. Paul, MN 55155-4194

Email: stuart.arkley@pca.state.mn.us

Phone: (651) 296-7774

Fax: (651) 296-8676

Proposals submitted in response to the Request for Proposals in this advertisement must be received at the address above no later

than 2:30 p.m. Central Time on January 6, 2003. Late proposals will not be considered.

This request does not obligate the state to complete the work contemplated in this notice. The state reserves the right to cancel

this solicitation. All expenses incurred in responding to this notice are solely the responsibility of the responder.
ATTACHMENT B 

MPCA Request for Proposal 
1 

 REQUEST FOR PROPOSALS

Minnesota Pollution Control Agency

Project Overview

 The Minnesota Pollution Control Agency (MPCA) requests proposals to survey and report on the potential 

impacts of the federal regional haze rule on the taconite industry in Minnesota. This rule requires certain sources to 

conduct an initial analysis that may lead to a more detailed assessment and installation of emissions controls that conform 

to Best Available Retrofit Technology (BART) requirements. The taconite industry has been identified by the MPCA as 

one of the industries for which a BART analysis is required. This project will provide a general analysis for the industry 

as a whole that can be used by both the MPCA and the taconite industry itself as a basis for planning purposes and for any 

facility-specific detailed assessments that will follow. 

 MPCA staff met with representatives of the six Minnesota taconite plants on October 3, 2002, to explain the 

scope of the proposed project and to determine the level of interest from the industry. The industry representatives 

expressed support and requested the option to review work products at key stages of the project. 

 The U.S. Environmental Protection Agency (EPA) issued BART determination guidelines on July 20, 2001, that 

will serve as a framework for this project. However, because some of these guidelines are still subject to legal challenge 

and because the guidelines are not yet supported by case histories, responders are encouraged to demonstrate creativity in 

their proposals in order to ensure that a comprehensive package is delivered. 

 This project must be completed by September 30, 2003. Due to the expedited nature of the contract, preference 

will be given to responders that can demonstrate substantial experience in working with both the taconite industry and air 

quality rules. Each contract responder must list the taconite companies that it has worked for in the past five years and 

that it is currently working for. If an existing contract is in place, the responder must explain why the new proposal does 

not create a conflict of interest. 

The contractor will be expected to work directly with MPCA staff, representatives of individual facilities and any 

appointed contacts for the industry as a whole. Representatives of the taconite industry will be involved in the selection 

process and in reviewing draft work products, including the draft final report. 

Goal

 The MPCA expects an overall assessment of the effects of the BART requirements on the taconite industry that 

can be used by both the industry and the MPCA for planning purposes and as the basis of further technical work. The 

analysis should provide each taconite facility with enough information to use as a baseline to begin a detailed assessment 

if required. Furthermore, the analysis should be structured to help ensure that each facility conducts its engineering 

assessments the same way, thereby promoting the consistency that will aid the MPCA’s review of those assessments. 

The MPCA also expects that the project will provide enough baseline information to initiate its own preliminary 

assessments, which are likely to be necessary to develop state implementation plan (SIP) submittals that will be due to 

EPA between 2006 and 2008. 
2 

Sample Tasks

1. Summarize EPA regional haze regulations as they apply to the taconite industry. 

2. Summarize BART requirements as they apply to the industry. 

3. Identify existing state and federal rules (e. g. Maximum Achievable Control Technology) that might help identify 

what BART is for the industry. Summarize the likely impacts of known future regulations. Include Michigan and 

Canadian requirements if appropriate. 

4. Identify facilities that may be subject to BART requirements (the MPCA has already done a survey that could be 

incorporated here). 

5. Using EPA’s draft BART guidance (or final if available), identify in a general sense, the control technology options 

for the industry. The draft guidance was published in the Federal Register on July 20, 2001 (FR July 20, 2001 p. 

38108-38135). Consider: 

• Available retrofit options [FR July 20, 2001 p. 38122] (include options from both outside and within the 

taconite industry) 

• Control equipment in place or likely to be in place [FR July 20, 2001 p. 38123] 

• The capital and operating costs of the control options [FR July 20, 2001 p. 38125] 

• The remaining useful life of the facility [FR July 20, 2001 p. 38126] 

• Energy and non-air quality environmental impacts of controls [FR July 20, 2001 p. 38129] 

• The control effectiveness of each option [FR July 20, 2001 p. 38126] 

• The “affordability” of controls [FR July 20, 2001 p. 38131] 

6. Estimate the reductions in visibility degrading pollutants (NOx, SO2, PM2.5 ((or PM10 if equivalent)), VOC, NH4) from 

control options. 

7. Consider the cost implications of implementing BART at those sources that supply needed services (such as fuel and 

power providers) to the taconite companies. Include an investigation of the capability of those suppliers to pass their 

costs along to the taconite industry, an estimate of the magnitude of the cost transfer, and an assessment of the likely 

effects of transferring those costs on the economic (affordability) analyses that the taconite companies must perform. 

The MPCA expects that items 5 and 6 will form the bulk of the deliverables of the project. The MPCA’s selection 

process will be based largely on how proposals address these items and the degree of creativity in each proposal. 

The contractor will work closely with industry and MPCA personnel. Depending on the details of the proposal, it is 

possible that the contractor will prepare outlines or rough drafts of certain products, which will be reviewed or appended 

by industry or MPCA staff. The number of steps relying on such MPCA or industry input should be kept to a minimum. 

The contract will begin on the date stated in the contract or upon full execution of the contract, whichever is later, and will

be completed by September 30, 2003. 

Responders are encouraged to propose additional tasks or activities if they will substantially improve the results of the 

project. These items should be separated from the required items on the cost proposal. 

This request for proposal does not obligate the state to award a contract or complete the project, and the state reserves the 

right to cancel the solicitation if it is considered to be in its best interest. 
3 

Prospective responders who have any questions regarding this request for proposal may contact: 

 Stuart Arkley, Project Manager 

 Policy & Planning Division 

 Minnesota Pollution Control Agency 

 520 Lafayette Road, St. Paul, MN 55155 

stuart.arkley@pca.state.mn.us 

 Telephone: 651-296-7774 

 Fax: 651-296-8676 

Other personnel are NOT authorized to discuss this request for proposal with responders, before the 

proposal submission deadline. Contact regarding this RFP with any personnel not listed above could 

result in disqualification. 

Questions must be submitted in writing (fax and e-mail will be accepted) by December 30, 2002. The MPCA will 

attempt to respond within 7 days of receipt of each question, depending on the complexity of the question and the 

total number of questions received. Copies of questions and MPCA responses will be sent to all responders to 

this request for proposal. 

Pre-Proposal Question and Answer Meeting 

The MPCA has scheduled a meeting at its St. Paul office on December 19, 2002, at 10 a.m. for the purpose of providing 

time for potential responders to ask questions about this project. All potential responders are invited to attend. The 

MPCA will be represented by the Project Manager and other key staff. Representatives of the taconite industry that plan 

to be involved in the selection process may also participate. Anyone interested in attending should confirm attendance by 

December 16, 2002. If no confirmations are received the meeting will be canceled. 

Proposal Content

The following will be considered minimum contents of the proposal: 

1. A statement of the objectives, goals, and tasks to show or demonstrate the responder's view of the nature of 

the contract. 

2. A description of the deliverables to be provided by the responder. 

3. An outline of the responder's background and experience with examples of similar work done by the 

responder and a list of personnel who will conduct the project, detailing their training, work experience, and 

hourly fees. No change in personnel assigned to the project will be permitted without the written approval of 

the state program manager. 

4. A detailed work plan that will identify the major tasks to be accomplished and be used as a scheduling and 

managing tool, as well as the basis for invoicing. 

5. Identification of the level of the MPCA’s participation in the contract, as well as any other services to be 

provided by the MPCA, and details of cost allowances for this participation. 
4 

All proposals must be sent to: 

 Stuart Arkley, Project Manager 

 Policy & Planning Division 

 Minnesota Pollution Control Agency 

 520 Lafayette Road, St. Paul, MN 55155 

All proposals must be received not later than 2:30 p.m., Central Time, on January 6, 2003, as indicated by a 

notation made by the MPCA Receptionist or Policy & Planning Division support staff. 

Late proposals will not be considered. 

All costs incurred in responding to this RFP will be borne by the responder. 

Fax and e-mail responses will not be considered. 

Submit three copies of the work proposal (not to include the cost proposal, which must be provided separately) 

and one set of work samples. Proposals are to be sealed in mailing envelopes or packages with the responder's 

name and address written on the outside. Each copy of the proposal must be signed in ink by an authorized 

member of the firm. 

Provide one copy of the cost proposal in a separately sealed envelope clearly marked on the outside “Cost 

Proposal” along with the firm’s name. For purposes of completing the cost proposal, the state does not make 

regular payments based upon the passage of time, it only pays for services performed or work delivered after it is 

accomplished. 

Proposals will be evaluated on “best value” as 80 percent qualifications and 20 percent on cost considerations. 

The cost proposal will not be opened by the review committee until after the qualifications points are awarded. 

Proposal Evaluation

All responses received by the deadline will be evaluated by representatives of the MPCA and a small group of 

representatives of the taconite industry. In some instances, an interview may be part of the evaluation process. A 

100-point scale will be used to create the final evaluation recommendation. The factors and weighting on which 

proposals will be judged are: 

1. Work plan 40% 

 2. Qualifications/experience of personnel working on the project 25% 

3. Cost detail 20% 

4. Expressed understanding of project objectives 10% 

5. Qualifications/experience of company 5% 
5 

General Requirements

Affidavit of Noncollusion 

Each responder must complete the attached Affidavit of Noncollusion and include it with the response. 

Conflicts of Interest

Responder must provide a list of all entities with which it has relationships that create, or appear to create, a conflict 

of interest with the work that is contemplated in this request for proposals. The list should indicate the name of the 

entity, the relationship, and a discussion of the conflict. 

Disposition of Responses

All materials submitted in response to this RFP will become property of the State and will become public record in 

accordance with Minnesota Statutes, section 13.591, after the evaluation process is completed. Pursuant to the statute, 

completion of the evaluation process occurs when the government entity has completed negotiating the contract with 

the selected vendor. If the Responder submits information in response to this RFP that it believes to be trade secret 

materials, as defined by the Minnesota Government Data Practices Act, Minn. Stat. § 13.37, the Responder must: 

• clearly mark all trade secret materials in its response at the time the response is submitted, 

• include a statement with its response justifying the trade secret designation for each item, and 

• defend any action seeking release of the materials it believes to be trade secret, and indemnify and hold 

harmless the State, its agents and employees, from any judgments or damages awarded against the State in 

favor of the party requesting the materials, and any and all costs connected with that defense. This 

indemnification survives the State’s award of a contract. In submitting a response to this RFP, the Responder 

agrees that this indemnification survives as long as the trade secret materials are in possession of the State. 

The State will not consider the prices submitted by the Responder to be proprietary or trade secret materials. 

Contingency Fees Prohibited 

Pursuant to Minnesota Statutes Section 10A.06, no person may act as or employ a lobbyist for compensation that is 

dependent upon the result or outcome of any legislation or administrative action. 

 

Sample Contract 

You should be aware of the State’s standard contract terms and conditions in preparing your response. A sample 

State of Minnesota Professional/Technical Services Contract is attached for your reference. Much of the language 

reflected in the contract is required by statute. If you take exception to any of the terms, conditions or language in the 

contract, you must indicate those exceptions in your response to the RFP; certain exceptions may result in your 

proposal being disqualified from further review and evaluation. Only those exceptions indicated in your response to 

the RFP will be available for discussion or negotiation.
6 

Reimbursements

Reimbursement for travel and subsistence expenses actually and necessarily incurred by the as a result of the contract 

will be in no greater amount than provided in the current "Commissioner’s Plan” promulgated by the commissioner of 

Employee Relations. Reimbursements will not be made for travel and subsistence expenses incurred outside 

Minnesota unless it has received the State’s prior written approval for out of state travel. Minnesota will be 

considered the home state for determining whether travel is out of state.

Organizational Conflicts of Interest

The responder warrants that, to the best of its knowledge and belief, and except as otherwise disclosed, there are no 

relevant facts or circumstances which could give rise to organizational conflicts of interest. An organizational conflict 

of interest exists when, because of existing or planned activities or because of relationships with other persons, a 

vendor is unable or potentially unable to render impartial assistance or advice to the State, or the vendor’s objectivity 

in performing the contract work is or might be otherwise impaired, or the vendor has an unfair competitive advantage. 

The responder agrees that, if after award, an organizational conflict of interest is discovered, an immediate and full 

disclosure in writing must be made to the Assistant Director of the Department of Administration’s Materials 

Management Division which must include a description of the action which the contractor has taken or proposes to 

take to avoid or mitigate such conflicts. If an organization conflict of interest is determined to exist, the State may, at 

its discretion, cancel the contract. In the event the responder was aware of an organizational conflict of interest prior 

to the award of the contract and did not disclose the conflict to the contracting officer, the State may terminate the 

contract for default. The provisions of this clause must be included in all subcontracts for work to be performed 

similar to the service provided by the prime contractor, and the terms “contract,” “contractor,” and “contracting 

officer” modified appropriately to preserve the State’s rights.

State Employees

In compliance with Minn. Stat. § 16C.07, the availability of this work is being offered to state employees. The State 

will evaluate the responses of any state employee, along with other responses to this Request for Proposals. 
7 

STATE OF MINNESOTA 

AFFIDAVIT OF NONCOLLUSION

I swear (or affirm) under the penalty of perjury: 

1. That I am the Responder (if the Responder is an individual), a partner in the company (if the Responder is a 

partnership), or an officer or employee of the responding corporation having authority to sign on its behalf (if the 

Responder is a corporation); 

2. That the attached proposal submitted in response to the ________________________ Request for Proposals has been 

arrived at by the Responder independently and has been submitted without collusion with and without any agreement, 

understanding or planned common course of action with, any other Responder of materials, supplies, equipment or 

services described in the Request for Proposal, designed to limit fair and open competition; 

3. That the contents of the proposal have not been communicated by the Responder or its employees or agents to any 

person not an employee or agent of the Responder and will not be communicated to any such persons prior to the 

official opening of the proposals; and 

4. That I am fully informed regarding the accuracy of the statements made in this affidavit. 

Responder’s Firm Name:___________________________________________ 

Authorized Signature: _____________________________________________ 

Date: __________________ 

 

Subscribed and sworn to me this ________ day of ___________ 

Notary Public 

My commission expires: ________
8 

If you take exception to any of the terms, conditions or language in the contract, you must indicate those 

exceptions in your response to the RFP; certain exceptions may result in your proposal being disqualified 

from further review and evaluation. Only those exceptions indicated in your response to the RFP will be 

available for discussion or negotiation.

STATE OF MINNESOTA 

 PROFESSIONAL AND TECHNICAL SERVICES CONTRACT

This contract is between the State of Minnesota, acting through its _______________ ("State") and _________ 

("Contractor"). 

Recitals

1. Under Minn. Stat. § 15.061 _________ the State is empowered to engage such assistance as deemed necessary. 

2. The State is in need of _______. 

3. The Contractor represents that it is duly qualified and agrees to perform all services described in this contract to the 

satisfaction of the State. 

Contract

1 Term of Contract 

 1.1 Effective date: ______________, or the date the State obtains all required signatures under Minnesota Statutes 

Section 16C.05, subdivision 2, whichever is later. 

The Contractor must not begin work under this contract until this contract is fully executed and the 

Contractor has been notified by the State’s Authorized Representative to begin the work. 

1.2 Expiration date: ______________, or until all obligations have been satisfactorily fulfilled, whichever occurs 

first. 

1.3 Survival of Terms. The following clauses survive the expiration or cancellation of this contract: 8. Liability; 9. 

State Audits; 10. Government Data Practices and Intellectual Property; 13. Publicity and Endorsement; 14. 

Governing Law, Jurisdiction, and Venue; and 16 Data Disclosure. 

2 Contractor’s Duties

The Contractor, who is not a state employee, will: 

3 Time 

The Contractor must comply with all the time requirements described in this contract. In the performance of this 

contract, time is of the essence. 

4 Consideration and Payment

 4.1 Consideration. The State will pay for all services performed by the Contractor under this contract as follows: 

(A) Compensation. The Contractor will be paid 

(B) Travel Expenses. Reimbursement for travel and subsistence expenses actually and necessarily incurred by 

the Contractor as a result of this contract will not exceed $___________ ; provided that the Contractor will 

be reimbursed for travel and subsistence expenses in the same manner and in no greater amount than 

provided in the current "Commissioner’s Plan” promulgated by the commissioner of Employee Relations. 

The Contractor will not be reimbursed for travel and subsistence expenses incurred outside Minnesota 

unless it has received the State’s prior written approval for out of state travel. Minnesota will be considered 

the home state for determining whether travel is out of state. 

 

(C) Total Obligation. The total obligation of the State for all compensation and reimbursements to the 

Contractor under this contract will not exceed $ ____________. 
9 

4.2.Payment

 (A) Invoices. The State will promptly pay the Contractor after the Contractor presents an itemized invoice for 

the services actually performed and the State's Authorized Representative accepts the invoiced services. 

Invoices must be submitted timely and according to the following schedule: 

 (B) Retainage. Under Minnesota Statutes Section 16C.08, subdivision 5(b), no more than 90% of the amount 

due under this contract may be paid until the final product of this contract has been reviewed by the State’s 

agency head. The balance due will be paid when the State’s agency head determines that the Contractor has 

satisfactorily fulfilled all the terms of this contract. 

 (C) Federal funds. (Where applicable, if blank this section does not apply) Payments under this contract will 

be made from federal funds obtained by the State through Title ______ CFDA number _________ of the 

__________ Act of _____. The Contractor is responsible for compliance with all federal requirements 

imposed on these funds and accepts full financial responsibility for any requirements imposed by the 

Contractor’s failure to comply with federal requirements. 

5 Conditions of Payment

All services provided by the Contractor under this contract must be performed to the State’s satisfaction, as 

determined at the sole discretion of the State’s Authorized Representative and in accordance with all applicable 

federal, state, and local laws, ordinances, rules, and regulations. The Contractor will not receive payment for 

work found by the State to be unsatisfactory or performed in violation of federal, state, or local law. 

6 Authorized Representatives 

The State's Authorized Representative is ____________, or his/her successor, and has the responsibility to 

monitor the Contractor’s performance and the authority to accept the services provided under this contract. If the 

services are satisfactory, the State's Authorized Representative will certify acceptance on each invoice submitted 

for payment. 

The Contractor's Authorized Representative is __________, or his/her successor. If the Contractor’s Authorized 

Representative changes at any time during this contract, the Contractor must immediately notify the State. 

7 Assignment, Amendments, Waiver, and Contract Complete

7.1 Assignment. The Contractor may neither assign nor transfer any rights or obligations under this contract 

without the prior consent of the State and a fully executed Assignment Agreement, executed and approved by 

the same parties who executed and approved this contract, or their successors in office. 

7.2 Amendments. Any amendment to this contract must be in writing and will not be effective until it has been 

executed and approved by the same parties who executed and approved the original contract, or their 

successors in office. 

7.3 Waiver. If the State fails to enforce any provision of this contract, that failure does not waive the provision or 

its right to enforce it. 

7.4 Contract Complete. This contract contains all negotiations and agreements between the State and the 

Contractor. No other understanding regarding this contract, whether written or oral, may be used to bind 

either party. 

8 Liability

The Contractor must indemnify, save, and hold the State, its agents, and employees harmless from any claims or 

causes of action, including attorney’s fees incurred by the State, arising from the performance of this contract by 

the Contractor or the Contractor's agents or employees. This clause will not be construed to bar any legal 

remedies the Contractor may have for the State's failure to fulfill its obligations under this contract. 
10 

9 State Audits

Under Minn. Stat. § 16C.05, subd. 5, the Contractor’s books, records, documents, and accounting procedures and 

practices relevant to this contract are subject to examination by the State and/or the State Auditor or Legislative 

Auditor, as appropriate, for a minimum of six years from the end of this contract. 

10 Government Data Practices and Intellectual Property 

10.1. Government Data Practices. The Contractor and State must comply with the Minnesota Government Data 

Practices Act, Minn. Stat. Ch. 13, as it applies to all data provided by the State under this contract, and as it 

applies to all data created, collected, received, stored, used, maintained, or disseminated by the Contractor 

under this contract. The civil remedies of Minn. Stat. § 13.08 apply to the release of the data referred to in 

this clause by either the Contractor or the State. 

If the Contractor receives a request to release the data referred to in this Clause, the Contractor must 

immediately notify the State. The State will give the Contractor instructions concerning the release of the 

data to the requesting party before the data is released. 

10.2. Intellectual Property Rights.

(A) Intellectual Property Rights. The State owns all rights, title, and interest in all of the intellectual 

property rights, including copyrights, patents, trade secrets, trademarks, and service marks in the 

Works and Documents created and paid for under this contract. Works means all inventions, 

improvements, discoveries (whether or not patentable), databases, computer programs, reports, notes, 

studies, photographs, negatives, designs, drawings, specifications, materials, tapes, and disks 

conceived, reduced to practice, created or originated by the Contractor, its employees, agents, and 

subcontractors, either individually or jointly with others in the performance of this contract. Works 

includes “Documents.” Documents are the originals of any databases, computer programs, reports, 

notes, studies, photographs, negatives, designs, drawings, specifications, materials, tapes, disks, or 

other materials, whether in tangible or electronic forms, prepared by the Contractor, its employees, 

agents, or subcontractors, in the performance of this contract. The Documents will be the exclusive 

property of the State and all such Documents must be immediately returned to the State by the 

Contractor upon completion or cancellation of this contract. To the extent possible, those Works 

eligible for copyright protection under the United States Copyright Act will be deemed to be “works 

made for hire.” The Contractor assigns all right, title, and interest it may have in the Works and the 

Documents to the State. The Contractor must, at the request of the State, execute all papers and 

perform all other acts necessary to transfer or record the State’s ownership interest in the Works and 

Documents. 

(B) Obligations

1. Notification. Whenever any invention, improvement, or discovery (whether or not patentable) is 

made or conceived for the first time or actually or constructively reduced to practice by the Contractor, 

including its employees and subcontractors, in the performance of this contract, the Contractor will 

immediately give the State’s Authorized Representative written notice thereof, and must promptly furnish 

the Authorized Representative with complete information and/or disclosure thereon. 

2. Representation. The Contractor must perform all acts, and take all steps necessary to ensure that 

all intellectual property rights in the Works and Documents are the sole property of the State, and that 

neither Contractor nor its employees, agents, or subcontractors retain any interest in and to the Works and 

Documents. The Contractor represents and warrants that the Works and Documents do not and will not 

infringe upon any intellectual property rights of other persons or entities. Notwithstanding Clause 8, the 

Contractor will indemnify; defend, to the extent permitted by the Attorney General; and hold harmless the 

State, at the Contractor’s expense, from any action or claim brought against the State to the extent that it is 

based on a claim that all or part of the Works or Documents infringe upon the intellectual property rights of 

others. The Contractor will be responsible for payment of any and all such claims, demands, obligations, 

liabilities, costs, and damages, including but not limited to, attorney fees. If such a claim or action arises, or 
11 

in the Contractor’s or the State’s opinion is likely to arise, the Contractor must, at the State’s discretion, 

either procure for the State the right or license to use the intellectual property rights at issue or replace or 

modify the allegedly infringing Works or Documents as necessary and appropriate to obviate the 

infringement claim. This remedy of the State will be in addition to and not exclusive of other remedies 

provided by law. 

11 Workers’ Compensation 

The Contractor certifies that it is in compliance with Minn. Stat. § 176.181, subd. 2, pertaining to workers’ 

compensation insurance coverage. The Contractor’s employees and agents will not be considered State 

employees. Any claims that may arise under the Minnesota Workers’ Compensation Act on behalf of these 

employees or agents and any claims made by any third party as a consequence of any act or omission on the part 

of these employees or agents are in no way the State’s obligation or responsibility. 

12 Publicity and Endorsement 

12.1 Publicity. Any publicity regarding the subject matter of this contract must identify the State as the 

sponsoring agency and must not be released without prior written approval from the State’s Authorized 

Representative. For purposes of this provision, publicity includes notices, informational pamphlets, press 

releases, research, reports, signs, and similar public notices prepared by or for the Contractor individually or 

jointly with others, or any subcontractors, with respect to the program, publications, or services provided 

resulting from this contract. 

 12.2 Endorsement. The Contractor must not claim that the State endorses its products or services. 

13 Governing Law, Jurisdiction, and Venue

Minnesota law, without regard to its choice-of-law provisions, governs this contract. Venue for all legal 

proceedings out of this contract, or its breach, must be in the appropriate state or federal court with competent 

jurisdiction in Ramsey County, Minnesota. 

14 Data Disclosure

Under Minn. Stat. § 270.66, and other applicable law, the Contractor consents to disclosure of its social security 

number, federal employer tax identification number, and/or Minnesota tax identification number, already 

provided to the State, to federal and state agencies and state personnel involved in the payment of state 

obligations. These identification numbers may be used in the enforcement of federal and state laws which could 

result in action requiring the Contractor to file state tax returns, pay delinquent state tax liabilities, if any, or pay 

other state liabilities. 

15 Payment to Subcontractors

(If applicable) As required by Minn. Stat. § 16A.1245, the prime contractor must pay all subcontractors, less any 

retainage, within 10 calendar days of the prime contractor's receipt of payment from the State for undisputed 

services provided by the subcontractor(s) and must pay interest at the rate of one and one-half percent per month 

or any part of a month to the subcontractor(s) on any undisputed amount not paid on time to the subcontractor(s).

16 Minn. Stat. § 181.59 The vendor will comply with the provisions of Minn. Stat. § 181.59 which requires: 

Every contract for or on behalf of the state of Minnesota, or any county, city, town, township, school, 

school district, or any other district in the state, for materials, supplies, or construction shall contain 

provisions by which the contractor agrees: (1) That, in the hiring of common or skilled labor for the 

performance of any work under any contract, or any subcontract, no contractor, material supplier, or 

vendor, shall, by reason of race, creed, or color, discriminate against the person or persons who are 

citizens of the United States or resident aliens who are qualified and available to perform the work to 

which the employment relates; (2) That no contractor, material supplier, or vendor, shall, in any 

manner, discriminate against, or intimidate, or prevent the employment of any person or persons

identified in clause (1) of this section, or on being hired, prevent, or conspire to prevent, the person or 
12 

persons from the performance of work under any contract on account of race, creed, or color; (3) That 

a violation of this section is a misdemeanor; and (4) That this contract may be canceled or terminated 

by the state, county, city, town, school board, or any other person authorized to grant the contracts for 

employment, and all money due, or to become due under the contract, may be forfeited for a second 

or any subsequent violation of the terms or conditions of this contract. 

17 Termination

17.1 Termination by the State. The State or commissioner of Administration may cancel this contract at any 

time, with or without cause, upon 30 days’ written notice to the Contractor. Upon termination, the Contractor will 

be entitled to payment, determined on a pro rata basis, for services satisfactorily performed. 

17.2 Termination for Insufficient Funding. The State may immediately terminate this contract if it does not 

obtain funding from the Minnesota Legislature, or other funding source; or if funding cannot be continued at a 

level sufficient to allow for the payment of the services covered here. Termination must be by written or fax 

notice to the Contractor. The State is not obligated to pay for any services that are provided after notice and 

effective date of termination. However, the Contractor will be entitled to payment, determined on a pro rata basis, 

for services satisfactorily performed to the extent that funds are available. The State will not be assessed any 

penalty if the contract is terminated because of the decision of the Minnesota Legislature, or other funding source, 

not to appropriate funds. The State must provide the Contractor notice of the lack of funding within a reasonable 

time of the State’s receiving that notice. 
ATTACHMENT C 

March 18, 2003, Working Group Meeting Minutes 
MPCA Taconite BART Project 

March 18, 2003, Working Group Meeting Minutes 

List of Working Group Attendees (in alphabetical order): 

Name Representing E-mail Address Phone Number 

Brad Anderson EVTAC brada@evtac.com (218) 744-7849 

Stuart Arkley MPCA stuart.arkley@state.mn.us (651) 296-7774 

Nick Axtell Fond du Lac nickaxtell@fdlrez.com (218) 878-8012 

Dick Cordes MPCA richard.cordes@state.mn.us (651) 296-8157 

Sarah Disch Barr Engineering Co. sdisch@barr.com (952) 832-2789 

Latisha Gietzen (via 

conference call) 

National Steel Pellet Co. lgietzen@nationalsteel.com (218) 778-8672 

Beth Havlik Barr Engineering Co. bhavlik@barr.com (952) 832-2640 

Gus Josephson Ispat Inland Mining Co. grjoseph@ispatinlandmining.com (218) 749-5910 

Jack Kennedy Barr Engineering Co. jkennedy@barr.com (952) 832-2913 

Brandon Krogh (via 

conference call) 

MN Power bkrogh@mnpower.com (218) 723-3954 

David Pohlman National Park Service david_pohlman@nps.gov (651) 290-3801 

George Pruchnofski Barr Engineering Co. gpruchnofski@barr.com (952) 832-2638 

Joel Trinkle Barr Engineering Co. jtrinkle@barr.com (952) 832-2870 

Joy Wiecks Fond du Lac joywiecks@fdlrez.com (218) 878-8008 

Review of Barr’s Work Plan: 

I. Task 1 – Hold Working Group Coordination Meeting 

a. Introductions (see attendee list above) 

b. Communication 

i. E-mail all correspondence to Stuart Arkley; Stuart will forward as needed 

ii. Stuart will disseminate reports 

c. Project deliverables 

i. Optional Task 1 was chosen by MPCA not to be completed 

ii. Optional Task 2 was chosen by MPCA to be completed 

d. General Regional Haze (RH) and Best Available Retrofit Technology (BART) 

discussion 

i. RH funding – federal (EPA) dollars, of which some is allocated to meeting 

Federal RH regulations. September 30 project deadline is established by 

MPCA to match end of Federal government’s fiscal year. 

ii. Why taconite industry? 

1. MPCA BART Survey found many taconite companies have BART-eligible 

units 

2. Taconite industry is unique and localized in Minnesota 

3. Many utilities and sugar beet companies also on Survey 

4. Utilities will likely be dealt with through other planning organizations or 

trade organizations 

5. Primary BART-eligible units at sugar beet companies are external 

combustion units, so they can look to utilities for guidance 

iii. Agencies potentially involved in working group 

1. Central States Regional Air Planning Association (CenRAP) / Central 

States Air Resource Agencies (CenSARA) 

a. CenRAP includes tribal organizations and deals specifically with 

RH 

b. Joy Wiecks and Brandon Krogh are on CenRAP; they will 

disseminate information to the group as appropriate 
MPCA Taconite BART Project – March 18, 2003 Working Group Meeting Minutes 

2 of 4 

2. EPA 

a. No specific expertise in taconite compared to MPCA staff; they 

may assist in review of documents but will not be actively 

involved, since it is the state’s responsibility. 

b. Tim Smith at EPA in Research Triangle Park, NC, oversees 

regional haze implementation from a Federal level. We may 

work with Tim as necessary regarding interpretation of RH and 

BART provisions to this project. 

3. MPCA 

4. Federal Land Managers (FLMs) 

5. Michigan Department of Environmental Quality (MDEQ): 

a. Two taconite plants in Michigan 

b. Working group felt that at least informal communications with a 

relevant organization in Michigan is appropriate 

c. MDEQ will not have representation; however, we will informally 

communicate with LADCO (see next item) 

6. Lake Michigan Air Directors Consortium (LADCO): 

a. Joy Wiecks will carbon copy Mike Koerber, director of LADCO, 

on relevant communications and reports 

iv. User/Audience of Project Deliverables 

1. Deliverables should help Taconite industry in completing individual 

BART evaluations and promote consistency in the methods used by 

individual facilities 

2. Deliverables should help MPCA in reviewing future BART evaluations by 

taconite industry 

v. Class I Areas of concern: 

1. Voyageurs and Boundary Waters in northern MN 

2. Isle Royale has generally been excluded in the past by FLMs due to 

proximity – will re-evaluate as part of Optional Task 2, if necessary 

3. Rainbow Lakes in WI does not have a visibility air quality related value 

(AQRV) 

II. Task 2 – Conduct Taconite Industry Regional Haze Regulatory Study 

a. Task 2A – Review MPCA BART survey and categorize emission units that may be 

subject to BART 

i. Reviewed handout of categorized BART-eligible sources at MN taconite plants 

ii. BART-eligible sources 

1. Induration furnaces 

2. PM point process sources 

3. PM fugitive process sources 

iii. Definition of taconite iron ore processing plant (where does facility start?) 

1. MACT definition vs. PSD definition 

2. Precedent 

a. Stuart will check at MPCA for other sectors 

b. Barr and MPCA will conference call with Tim Smith, EPA (at 

Research Triangle Park) 

iv. BART-eligible sources: propose omitting from list 

1. External combustion – covered separately under separate source 

category (but some level of review will be necessary in order to 

complete Optional Task 2, and probably Tasks 3 and 4) 

2. Internal combustion 

a. No threshold in Guidance 

b. All emergency backup for electrical capabilities 

c. Small emissions, used infrequently 

3. Zn melt furnaces 

a. Reasonable to assume control not affordable 

b. Discuss insignificant activities with Tim Smith 
MPCA Taconite BART Project – March 18, 2003 Working Group Meeting Minutes 

3 of 4 

4. Mining (see II.a.ii. above) 

5. Co-gen electric plants 

a. Outside of scope 

b. Covered separately under separate source category 

b. Task 2B – Apply current EPA regional haze regulations and BART guidance to the 

taconite industry 

i. Status of proposed MACT 

1. EPA issued proposed MACT, invited and received comments 

2. Meeting 3/18/03 AM with rule writer Steve Fruh and Conrad Chin to 

discuss industry’s comments 

3. Delisting proposal in June 2003; final rule by August 2003 

4. Risk assessment will not help industry - Hg and fibers may become 

political issues 

c. Task 2E – Finalize Report of Taconite Industry Regional Haze Regulatory Study 

i. It was noted that the deadline for comments is incorrect. Barr will revise and 

re-submit the work scope to the working group. 

III. Task 3 – Conduct General Taconite Industry BART Screening 

a. Task 3A – Identify control technologies and practices for each emission unit category 

i. Visibility-impairing pollutants of concern: fine particulate matter, NOx, and 

SO2 

ii. Ammonia – Stuart will discuss any potential ammonia emissions in the Air 

Toxics Emissions Inventory (ATEI) at taconite plants with Chun Yi Wu, MPCA 

iii. VOC – not a pollutant that needs detailed analysis, since induration furnaces 

must have high oxygen levels, thus oxidizing VOC to products of combustion 

b. Task 3D – Evaluate economic, energy, and environmental impacts 

i. Attempt to make economic analysis cost-scalable 

ii. Hypothetical taconite facility – concern that a single representative facility will 

not meet the needs of the industry without also looking at the entire range of 

facilities. Barr to propose a hypothetical taconite facility to the working group 

before beginning this task. 

c. Task 3F – Finalize Report of Taconite Industry BART Evaluation 

i. It was noted that the deadline for comments is incorrect. Barr will revise and 

re-submit the work scope to the working group. 

IV. Task 4 – Conduct BART Affordability of Controls Evaluation 

a. See outline by George Pruchnofski of Barr 

V. Optional Task 2 – Perform CALPUFF Visibility Impacts Screening Analysis 

a. Reviewed handout map of the six taconite plants in relation to the receptor grid for 

Voyageurs and Boundary Waters 

b. Concern was raised as to the scalability of results from a few individual units to an 

entire plant. Although this is currently not one of the primary objectives of the 

analysis, Barr will investigate the scalability of results to an entire facility. 

VI. Action Items from Meeting 

a. Barr to summarize meeting minutes and update deadlines in Barr’s scope of work 

b. MPCA to internally discuss the merits of inviting other agencies to participate in 

working group 

c. Stuart Arkley will work with Chun Yi Wu at MPCA regarding any ammonia emissions 

from the taconite industry and communicate findings to Barr 

d. MPCA and Barr to discuss with EPA about inclusion/exclusion of certain units 

(specifically, mining operations) in a BART evaluation; summarize these discussions 

with EPA and communicate findings to working group 

e. Barr to propose hypothetical taconite facility in Task 3D and Optional Task 2 

Handouts at Meeting: 

- Attachment 1: Barr’s project work scope – the document attached to these minutes has 

been revised to incorporate corrected deadlines for report comments 
MPCA Taconite BART Project – March 18, 2003 Working Group Meeting Minutes 

4 of 4 

- Attachment 2: Preliminary categorization of BART-eligible units at the Minnesota taconite 

plants 

- Attachment 3: Map showing Minnesota taconite plants in relation to Voyageurs and 

Boundary Waters 

- Attachment 4: Outline for Task 4 of the project 
Barr Engineering Company Page 4 

Project Deliverables 

Table 1 on the following page describes each proposed project deliverable and provides a schedule for 

completion. Our schedule assumes a project initiation date of March 3, 2003. The schedule for completion 

is subject to change if the project begins later. 

As described in the work plan, Barr proposes to prepare two key reports for this project. The reports will 

combine the individual tasks necessary to meet project objectives 1 through 4 in the Project Overview and 

Objectives section of this proposal. By completing only three reports for the project rather than submitting 

individual reports for each task, overall project costs are significantly reduced and review time by the 

working group is optimized. As a result, Barr expects to complete the required items of this project by the 

end of August, one month ahead of the September 30, 2003 required completion date. 
Barr Engineering Company Page 5 

Table 1. Summary of project deliverables and schedule for completion 

Work Plan Deliverable Description of Deliverable and Relationship to 

Project Objectives 

Schedule for 

Completion 

Task 1 Deliverables: Agenda and 

summary minutes of working 

group kick-off meeting 

Barr will prepare an agenda and summarize minutes 

of the working group kick-off meeting, which will 

be scheduled for the week of March 10, 2003. 

Agenda: March 7 

Minutes: 

March 18 

Task 2 Deliverables: Report on 

“Taconite Industry Regional Haze 

Regulatory Study” (working title; 

all final titles subject to working 

group approval) 

Barr will provide for the working group’s review an 

initial draft and a final version of the regulatory 

study, which will fulfill project objectives 1 and 2 in 

the Project Overview and Objectives section of this 

proposal. 

Draft: April 18 

Final: May 23 

Task 3 Deliverables: Report on 

“Taconite Industry BART 

Evaluation” 

Barr will provide for the working group’s review an 

initial draft and a final version of the BART 

evaluation report, which fulfills project objective 3 

in the Project Overview and Objectives section of 

this proposal. 

Draft: June 30 

Final: August 22 

Task 4 Deliverable: Summary 

Report on the BART affordability 

issue as applied to the taconite 

industry 

Barr will prepare a report to the working group 

summarizing discussions on the BART affordability 

issue and provide pass-through cost information, 

which fulfills project objective 4 in the Project 

Overview and Objectives section of this proposal. 

Draft: July 14 

Final: August 29 

Routine progress reports Barr will provide progress reports detailing work 

performed, upcoming tasks to be completed, budget 

status, and schedule status. 

Every four weeks, 

consistent with 

invoice frequency 

Optional Task 1 Deliverable: 

Customized BART evaluation 

tools for the taconite industry 

If this optional task is chosen, Barr will provide 

user-friendly input and output screens and a user 

guide for the cost spreadsheets so that taconite 

facilities can uniformly perform BART evaluations. 

September 19 or 

four weeks after 

notice is given to 

proceed with this 

task, whichever is 

later 

Optional Task 2 Deliverable: 

Results of CALPUFF visibility 

impacts screening analysis 

If this optional task is chosen, Barr will provide a 

memorandum summarizing results of a CALPUFF 

dispersion modeling analysis estimating the 

visibility impacts of a hypothetical taconite facility 

before and after BART application. 

September 26 or 

five weeks after 

notice is given to 

proceed with this 

task, whichever is 

later 
Barr Engineering Company Page 12 

Proposed Work Plan 

The proposed work plan is comprised of four primary tasks. Two optional tasks are also provided for your 

consideration. 

• Task 1: Hold working group coordination meeting 

• Task 2: Conduct taconite industry regional haze regulatory study 

[includes RFP sample tasks 1 through 4] 

• Task 3: Conduct general taconite industry BART screening 

[includes RFP sample tasks 5 (except affordability issue) and 6] 

• Task 4: Evaluate BART affordability issues 

[includes RFP sample task 5 (affordability issue only) and 7] 

• Optional Task 1: Customize BART evaluation tools for the taconite industry 

• Optional Task 2: Perform CALPUFF visibility impacts screening analysis 

Task 1. Hold Working Group Coordination Meeting 

The working group—MPCA personnel, representatives of the Minnesota taconite plants, and Barr’s 

primary project team members—will meet at Barr’s Minneapolis office during the week of March 10, 

2003. Barr will prepare a meeting agenda, which will be submitted to the MPCA during the week of 

March 3, 2003. The purpose of the meeting is three-fold: 

• Provide contact information. The working group will introduce themselves and provide their 

contact information and their roles in this project. Discussion should cover the need to include 

other participants, such as Michigan Department of Environmental Quality (MDEQ), EPA, or 

CENSARA (Central States Air Resource Agencies) staff, in the working group. 

• Establish lines of communication. The working group will decide on verbal, electronic, and 

written lines of communication. 

• Review work plan. The working group will review this work plan in detail and confirm 

important points and assumptions that best meet the project objectives, such as choosing emission 

unit categories and how the work products will be used in completing analyses outside the scope 

of this project. 
Barr Engineering Company Page 13 

We anticipate that this meeting will last two to three hours. Following the meeting, Barr will prepare a 

summary of the meeting minutes and route this via e-mail to the working group. 

Task 1 Barr Deliverables: 

• Agenda for the working group kick-off meeting 

• Summary minutes of the working group kick-off meeting 

Task 1 Assumptions: 

• The kick-off meeting will be held at Barr’s Minneapolis office.

• All working group members will participate in this meeting either in person or by conference call.

• MPCA will provide results of the BART survey for the individual taconite facilities (needed for 

Task 2A) prior to or at this meeting.

Task 2. Conduct Taconite Industry Regional Haze Regulatory Study 

Task 2 will fulfill project objectives 1 and 2 outlined in the “Project Overview and Objectives” section of 

this proposal. It has five elements, detailed below as Tasks 2A–2E. 

Task 2A: Review MPCA BART survey and categorize emission units that may be subject to BART 

An appropriate first step in evaluating BART for a group of sources is to categorize emission units within 

the “taconite ore processing facilities” source category. Grouping several emission units into a few 

categories will allow efficient evaluation of available control technology options for the industry. Based 

on Barr’s experience with the taconite industry, we propose three emission unit categories on which the 

regulatory study in Task 2 and the BART evaluation in Task 3 will be based. These categories will be 

reviewed and finalized as part of this task. 

Table 2 on the following page identifies the three proposed emission unit categories, individual emission 

units in each category, and expected control technology options to be evaluated. 

Task 2A Assumptions: 

• Results from the MPCA BART survey for the individual taconite plants will be provided prior to 

or at the working group kick-off meeting in Task 1.

• For purposes of estimating cost and schedule for this project, up to three emission unit types (e.g., 

induration furnace, crusher, and cooler) will be evaluated. 
Barr Engineering Company Page 14 

Table 2. Preliminary Taconite Emission Unit Categories and Control Technology Options 

Source Types Sources Control Technology Options 

Particulate Fugitive 

Source 

- Main roads 

- Transfer conveyors 

- Stockpiles 

- Pellet loading 

- Dust suppression 

- Enclosure 

Particulate Point 

Source 

- Ore dump pits 

- Ore conveyors 

- Crushers 

- Additive handling 

- Pellet coolers 

- Screens 

- Product conveyors 

- Enclosure 

- Scrubber (low/high efficiency)

- Fabric filter 

- ESP 

Induration Point 

Source 

(Particulate and 

Combustion 

Emissions) 

Straight grate furnaces at: 

- Hibbing Taconite Company 

- Ispat-Inland Steel Mining Company 

- Northshore Mining Company 

Grate-kiln systems at: 

- US Steel Minnesota Ore Operations 

- National Steel Pellet Company 

- EVTAC Mining, LLC 

Particulate: 

- Multiclone 

- Baghouse 

- Scrubber 

- ESP/WESP 

SO2:

- WESP 

- Scrubber (low/high efficiency) 

NOx: 

- Combustion control 

- Low-NOx burner 

- SCR 

- SNCR 

Task 2B: Apply current EPA regional haze regulations and BART guidance to the 

taconite industry 

Barr will review and summarize the final regional haze regulations and the proposed BART guidance as it 

applies to the taconite industry. In addition, we will summarize recent court opinions concerning the 

legality of certain BART provisions. This is considered necessary to help form an appropriate procedure 

for evaluating BART (see Task 3) that will not conflict with present or future EPA regulations or 

guidance. 

Task 2B Assumptions: 

• The 1999 regional haze regulations, the 2001 BART guidance, and the May and September 2002 

court rulings comprise the documents for review under this task. Any new regulations or court 

decisions issued after January 6, 2003 may impact the schedule, scope, and cost of the project. 
Barr Engineering Company Page 15 

Task 2C: Summarize existing and possible future standards of performance applicable to 

the taconite industry 

Barr will examine the following state and federal standards of performance in order to better understand 

how the taconite industry meets applicable emission limits: 

• Federal Standards of Performance for Metallic Mineral Processing Plants, 40 CFR part 60 

subpart LL 

• Proposed National Emission Standards for Hazardous Air Pollutants for Taconite Iron Ore 

Processing, 40 CFR part 63 subpart RRRRR 

• Minnesota Rules, Chapter 7011 

• Michigan Air Pollution Control Rules, Parts 3 through 12 

• Canadian provincial air quality standards of performance (focus on provinces where taconite 

processing facilities are located) 

In addition, Barr will gather and review BACT determinations from EPA, MPCA, and MDEQ for 

taconite facilities as well as operating permits for Minnesota and Michigan taconite facilities to pull 

together site-specific standards of performance and the methods used by these companies to meet them. 

The Taconite Iron Ore Processing NESHAPs was proposed on December 18, 2002. The taconite industry 

is in the process of reviewing available options to petition a delisting of Taconite Iron Ore Processing as a 

source category. As part of this project, Barr will evaluate the status of this effort and report our findings. 

Task 2C Assumptions: 

• Barr may request from MPCA a copy of taconite facility operating permits and related documents 

that we do not have in-house. We assume that MPCA will provide a copy of the requested 

documents in a timely manner.

Task 2D: Prepare initial draft report of Taconite Industry Regional Haze Regulatory Study 

We will outline our findings from Tasks 2A through 2C in a draft report, which will be submitted via 

e-mail as an Acrobat PDF file to the working group by April 18 for review. 

Task 2D Barr Deliverables: 

• Draft report of Taconite Industry Regional Haze Regulatory Study. 

Task 2E: Finalize report of Taconite Industry Regional Haze Regulatory Study 

The working group will review the initial draft report. Upon request, we will schedule a meeting in earlyto mid-April at Barr’s Minneapolis office to discuss the report. Assuming that all comments are provided 

to Barr by May 14, the final report will be prepared and sent to the MPCA contact by May 23, 2003. 
Barr Engineering Company Page 16 

Task 2E Barr Deliverables: 

• Final report of Taconite Industry Regional Haze Regulatory Study. 

Task 2E Assumptions: 

• Barr assumes that attending a review meeting and finalizing the draft report will involve a level of 

effort up to 20 person-hours.

Task 3. Conduct General Taconite Industry BART Screening 

Task 3 fulfills project objective 3 in the “Project Overview and Objectives” section of this proposal. It has 

six elements, Tasks 3A–3F, which are consistent with the steps in EPA’s BART guidance but have been 

customized to allow the use of a recent BACT study performed for a new taconite plant. 

In 2000, Barr began a prevention of significant deterioration (PSD) air permitting project for an entirely 

new taconite facility. The BACT analysis that Barr performed for that project—herein referred to as the 

“2000 Taconite BACT Analysis”—will serve as an excellent starting point for development of tools and 

evaluation of each BART step. 

Task 3A: Identify control technologies and practices for each emission unit category 

The first step in a case-by-case BART engineering analysis is to identify all available retrofit control 

technologies. Beginning with the emission unit category list in Table 2 (Task 2A), Barr will identify 

available control technologies and practices for the following pollutants of concern:1

• Sulfur dioxide 

• Nitrogen oxides 

• Particulate matter 

• Volatile organic compounds 

• Ammonia 

For particulate matter, PM10 will be used as an indicator, consistent with EPA’s BART guidance. Barr 

assumes that actual PM2.5 emissions data for the taconite emission units of concern will not be available 

for this study. 

Based on our experience in estimating and measuring pollutant emissions from taconite facilities, we 

believe that no significant ammonia emissions sources exist from taconite processes. Therefore, Barr 

assumes that ammonia will not need to be addressed in a BART evaluation unless it is released as 

ammonia slip from a control technology application (e.g., injected into a SCR catalyst bed or in an ESP). 

As shown in Table 2, Barr has narrowed the pollutants of concern for the induration point sources to 

PM10, SO2, and NOx. An induration furnace has relatively low VOC emissions because oxygen must be 

maintained at a high level in the unit as part of normal operation; therefore, the only practical VOC 

 

1

 See 66 FR 38119 for an EPA discussion on visibility-impairing pollutants. 
Barr Engineering Company Page 17 

emissions control is good operating practices. Other VOC control technologies will not be evaluated for 

induration point sources. 

In Task 3A, Barr will update its list of available control technology options by contacting control 

technology vendors and reviewing relevant journals (since 2000), websites, and other relevant literature 

listed in the EPA BART guidance.2

 

Task 3A Assumptions: 

• For particulate matter, PM10 will be used as an indicator. Emissions of PM2.5 will not be 

addressed in this study.

• A BART evaluation for VOC emissions from induration point sources will not be performed. 

• Ammonia will not need to be addressed in a BART evaluation for the taconite industry, unless it 

is emanated as ammonia slip from a control technology option. 

Task 3B: Eliminate technically infeasible control options 

The second step in EPA’s BART guidance is to review the technical feasibility of control options 

identified in Task 3A. As part of the 2000 Taconite BACT Analysis, we performed a technical feasibility 

analysis for all available control options. To meet BART guidance objectives, we will: 

• Assess the technical feasibility of any new control technology options identified in Task 3A 

• Re-examine the technical feasibility determination made in the 2000 Taconite BACT Analysis as 

applied to a BART source 

A control technology that is considered technically feasible for a new source may not be technically 

feasible as a retrofit.3

 For example, in the 2000 Taconite BACT Analysis, selective catalytic reduction 

(SCR) was considered a technically feasible control technology for a proposed grate-kiln furnace because 

the furnace could be designed to accommodate the catalyst bed at an appropriate temperature and 

pressure. It is possible that SCR may be found to be technically infeasible for an existing furnace not 

designed to accommodate SCR. 

Task 3B Assumptions: 

• We assume that up to two new control technologies will be identified in Task 3A and require a 

technical feasibility determination beyond the list of existing control technology options 

identified in Table 2. This project assumption is also important for Tasks 3C and 3D. 

 

2

 See 66 FR 38123 for EPA’s list of information sources to review for potentially applicable retrofit control 

technology alternatives. 

3

 In 64 FR 38123, EPA states, “We do not consider BART as a requirement to redesign the source when considering 

available control alternatives.” 
Barr Engineering Company Page 18 

Task 3C: Rank remaining control technologies by control effectiveness 

The third step in EPA’s BART guidance is to rank technically feasible control technologies by their 

control effectiveness. Barr evaluated the percent control efficiency of technical feasible control 

technologies as part of the 2000 Taconite BACT Analysis. Barr will update the control-effectiveness data 

based on conversations with control technology vendors in Task 3A. 

Task 3D: Evaluate economic, energy, and environmental impacts 

The fourth step in EPA’s BART guidance is to perform an impacts analysis related to the economic, 

energy, and non-air quality environmental aspects of the control technology options. During the 2000 

Taconite BACT Analysis, we evaluated these impacts for control technologies installed at a new source. 

Barr will re-examine the impacts of all technically feasible control technologies as they apply to an 

existing taconite facility. 

To provide meaningful information from this task, Barr will use a hypothetical taconite facility 

representative of the taconite industry, as determined in Task 1 by the working group, to estimate the cost 

and impacts of control technology options. 

Task 3E: Prepare initial draft report of Taconite Industry BART Evaluation 

Barr will outline its findings from Tasks 3A through 3D in a report to MPCA. The draft report and 

corresponding control equipment cost spreadsheets will be submitted via e-mail to the working group by 

June 30, 2003, for review. 

Task 3E Barr Deliverables: 

• Draft report of Taconite Industry BART Evaluation. 

Task 3F: Finalize report of Taconite Industry BART Evaluation 

The working group will review the initial draft report. Upon request, we will schedule a meeting in June 

at Barr’s Minneapolis office to review and discuss the report. Assuming that all comments will be 

provided to Barr by July 31, the final report will be prepared and sent to the MPCA point of contact by 

August 22, 2003. 

Task 3F Barr Deliverables: 

• Final report of Taconite Industry BART Evaluation including calculation spreadsheets. 

Task 3F Assumptions: 

• Barr assumes that attending a review meeting and finalizing the draft report can be accomplished 

with a level of effort up to 30 person-hours.
Barr Engineering Company Page 19 

Task 4. Conduct BART Affordability of Controls Evaluation 

The affordability of controls is an important consideration for the state and the taconite industry, given the 

financial condition of the industry and foreign competition’s current impact on taconite product prices. 

Current and anticipated market price trends from publicly available literature will be reviewed and 

summarized. Other industry-wide affordability issues will also be briefly examined and summarized if 

brought forward by working group members and agreed to by the MPCA. However, facility-specific 

affordability issues will not be considered as part of this project. 

Barr will contact major taconite industry service providers (e.g., power, fuel) to attempt to identify passthrough costs to the taconite industry that are anticipated to result from the regional haze SIP. The results 

of these communications will be reported. 

Additionally, Barr will prepare a cost summary template to present total anticipated taconite facility 

internal costs and pass-through costs of service providers. The template will allow for the presentation of 

cost increases per ton of product. These costs can be compared to the current and anticipated price for 

taconite product. A sample table will be completed using the results of Task 3 and the anticipated passthrough costs obtained from service providers. 

Task 4 Barr Deliverable: 

• A draft summary report and cost table will be prepared for work group review and comment. 

Barr will consider the comments in preparing the final memo and cost table. 

Task 4 Assumptions:

• General industry affordability issues will be addressed. Facility-specific affordability issues are 

outside the scope of this project. 

Optional Task 1. Customize BART Evaluation Tools for the Taconite Facilities 

An optional task that Barr will perform upon MPCA’s request is to customize control cost spreadsheets 

and related tools for use by the taconite industry. The spreadsheets will have user-friendly input screens 

that each facility can use to input site-specific information necessary to evaluate BART for an emission 

unit and control technology option and review the results. Accompanying these tools will be a guide that 

describes steps and procedures that the user should follow. The key value in this tool is that it provides 

ease of use and uniformity in both the initial BART evaluation by the taconite industry and subsequent 

review by a regulatory agency. 

Optional Task 1 Barr Deliverable: 

• Spreadsheets, related tools, and a user’s guide to help provide consistent site-specific BART 

evaluations for the taconite industry. 

Optional Task 1 Assumptions:

• Spreadsheets and tools developed in Task 3 will form the basis for the customized BART 

evaluation tools. No new spreadsheets or other tools are expected to be developed as part of this 

task. 
Barr Engineering Company Page 20 

Optional Task 2. Perform CALPUFF visibility impacts screening analysis. 

An optional task that Barr will perform upon MPCA’s request is a visibility impacts screening analysis 

for a hypothetical taconite facility before and after BART application. Barr will use the Federal Land 

Managers’ Air Quality Related Values Workgroup (FLAG) Phase I Report (December 2000) as protocol 

for estimating visibility impacts. The FLAG report calls for use of the CALMET/CALPUFF/CALPOST 

modeling system, with specific information provided for relative humidity to estimate the effects of 

hygroscopic particles. 

Barr will propose and the working group will confirm the pollutant emission rates and relevant source 

parameters for a hypothetical taconite facility that will be used in the analysis. The working group will 

also decide upon three post-BART scenarios to estimate different levels of controlled emissions from the 

modeled emission units. Barr will model the visibility impairment from the facility as a “change in 

extinction” in units of percent, in accordance with the FLAG report. The following results will be 

provided in a memorandum: 

• Pre-BART change in extinction from the facility 

• Post-BART change in extinction from the facility for each scenario 

• Contribution/culpability from each pollutant and source. 

We believe that this analysis will serve to prepare a framework for future dispersion modeling analyses. 

Applications of the results of this modeling analysis by itself are limited. 

Optional Task 2 Barr Deliverable: 

• Memorandum summarizing results of the visibility impacts screening analysis before and after 

BART application. 

Optional Task 2 Assumptions:

• Barr will not perform modeling iterations using different emission rates or source parameters 

other than those established initially by the working group. 

• Barr will use an existing CALMET system that was prepared for another project. Electronic 

CALMET input and output files will not be provided to MPCA. Electronic CALPUFF and 

CALPOST input and output files will be provided to MPCA upon request. 

• The December 2000 FLAG Report will serve as the basis for modeling protocol. Additions or 

changes to FLAG guidance since this report will not be incorporated into this analysis. 

• The results of this analysis will have limited application. A comprehensive dispersion modeling 

analysis with existent facility emissions data will be needed in order to determine visibility 

impacts on Class I areas from the taconite industry. 
ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

FS004 Unpaved Roads - Hauling Waste & Ore 1.00 Particulate Fugitive Source 1.01 Unpaved Roads

FS008 Unpaved Roads - Lt truck traffic around mine 1.00 Particulate Fugitive Source 1.01 Unpaved RoadsFS001 Unpaved Roads - Coarse tailings to tailings basin 1.00 Particulate Fugitive Source 1.01 Unpaved RoadsFS012 Unpaved Roads - Lt truck traffic around plant 1.00 Particulate Fugitive Source 1.01 Unpaved RoadsFS006 North Mine Transfer to Surge 1.00 Particulate Fugitive Source 1.02 Material Handling (Conveyor)FS007 South Mine Transfer to Surge 1.00 Particulate Fugitive Source 1.02 Material Handling (Conveyor)FS005 Coarse Ore Surge Dump 1.00 Particulate Fugitive Source 1.02 Material Handling (Conveyor)FS029 Fire Ore Surge (9F to 10 transfer) 1.00 Particulate Fugitive Source 1.02 Material Handling (Conveyor)FS030 Fine Ore Surge (10 to pile transfer) 1.00 Particulate Fugitive Source 1.02 Material Handling (Conveyor)FS031 Line 1 Pellet Transfer (21 to 21B) 1.00 Particulate Fugitive Source 1.02 Material Handling (Conveyor)FS002 Truck Unloading 1.00 Particulate Fugitive Source 1.03 Material Handling (Mobile Equipment)FS024 Pellet Reclaim - Pocket to pile 2 (FEL) 1.00 Particulate Fugitive Source 1.03 Material Handling (Mobile Equipment)FS001 Wind Erosion - Waste & Ore Stockpiles 1.00 Particulate Fugitive Source 1.03 Wind Erosion (Stockpile)FS003 Wind Erosion - Ballast Stockpile 1.00 Particulate Fugitive Source 1.03 Wind Erosion (Stockpile)FS004 Wind Erosion - Concentrate Stockpiles 1.00 Particulate Fugitive Source 1.03 Wind Erosion (Stockpile)FS014 Pelet Reclaim - Screen to belt 22 transfer 1.00 Particulate Fugitive Source 1.04 Material Handling (Other)FS033 Pellet Loadout Railcar Loading 1.00 Particulate Fugitive Source 1.04 Material Handling (Other)FS002 Wind Erosion - Tailings basin (active area) 1.00 Particulate Fugitive Source 1.04 Wind Erosion (Other)

c FS Central Shops - multiple sources 1.00 Particulate Fugitive Source Uncategorized

001 North Primary Crushing 2.00 Particulate Point Source 2.01 Crushing002 North Secondary Crushing 2.00 Particulate Point Source 2.01 Crushing004 South Primary Crushing 2.00 Particulate Point Source 2.01 Crushing005 South Secondary Crushing 2.00 Particulate Point Source 2.01 Crushing005 Third Stage Crusher 1 2.00 Particulate Point Source 2.01 Crushing006 Third Stage Crusher 2 2.00 Particulate Point Source 2.01 Crushing007 Third Stage Crusher 3 2.00 Particulate Point Source 2.01 Crushing008 Third Stage Crusher 4 2.00 Particulate Point Source 2.01 Crushing009 Third Stage Crusher 5 2.00 Particulate Point Source 2.01 Crushing011 Fourth Stage Crusher 1 2.00 Particulate Point Source 2.01 Crushing012 Fourth Stage Crusher 2 2.00 Particulate Point Source 2.01 Crushing013 Fourth Stage Crusher 3 2.00 Particulate Point Source 2.01 Crushing014 Fourth Stage Crusher 4 2.00 Particulate Point Source 2.01 Crushing015 Fourth Stage Crusher 5 2.00 Particulate Point Source 2.01 Crushing016 Fourth Stage Crusher 6 2.00 Particulate Point Source 2.01 Crushing017 Fourth Stage Crusher 7 2.00 Particulate Point Source 2.01 Crushing018 Fourth Stage Crusher 8 2.00 Particulate Point Source 2.01 Crushing001 Primary Crusher 2.00 Particulate Point Source 2.01 Crushing003 Secondary Crusher System 2.00 Particulate Point Source 2.01 Crushing004 Secondary Crusher System 2.00 Particulate Point Source 2.01 Crushing005 Secondary Crusher System 2.00 Particulate Point Source 2.01 Crushing007 Tertiary Crusher System 2.00 Particulate Point Source 2.01 Crushing008 Tertiary Crusher System 2.00 Particulate Point Source 2.01 Crushing009 Tertiary Crusher System 2.00 Particulate Point Source 2.01 Crushing010 Tertiary Crusher System 2.00 Particulate Point Source 2.01 Crushing

001 Gyrator Crusher - Primary Crusher No. 1 2.00 Particulate Point Source 2.01 Crushing002 Gyrator Crusher - Primary Crusher No. 2 2.00 Particulate Point Source 2.01 Crushing007 Crusher 2 2.00 Particulate Point Source 2.01 Crushing

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

Task 2A\BART Survey Data Sorted.xls

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ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

008 Crusher 2a 2.00 Particulate Point Source 2.01 Crushing

c 013 Step I Coarse Crusher 2.00 Particulate Point Source 2.01 Crushingc 014 Step I Coarse Crusher 2.00 Particulate Point Source 2.01 Crushingc 015 Step II Coarse Crusher 2.00 Particulate Point Source 2.01 Crushingc 016 Step II Coarse Crusher 2.00 Particulate Point Source 2.01 Crushingc 054 Secondary Crusher L1 2.00 Particulate Point Source 2.01 Crushingc 055 Secondary Crusher L2 2.00 Particulate Point Source 2.01 Crushingc 056 Secondary Crusher L3 2.00 Particulate Point Source 2.01 Crushingc 057 Secondary Crusher L4 2.00 Particulate Point Source 2.01 Crushingc 069 Tertiary Crusher L1 2.00 Particulate Point Source 2.01 Crushingc 070 Tertiary Crusher L2 2.00 Particulate Point Source 2.01 Crushingc 071 Tertiary Crusher L3 2.00 Particulate Point Source 2.01 Crushingc 072 Tertiary Crusher L4 2.00 Particulate Point Source 2.01 Crushingc 073 Tertiary Crusher L5 2.00 Particulate Point Source 2.01 Crushingc 074 Tertiary Crusher L6 2.00 Particulate Point Source 2.01 Crushingc 075 Tertiary Crusher L7 2.00 Particulate Point Source 2.01 Crushingc 076 Tertiary Crusher L8 2.00 Particulate Point Source 2.01 Crushingc 077 Tertiary Crusher L9 2.00 Particulate Point Source 2.01 Crushingc 078 Tertiary Crusher L10 2.00 Particulate Point Source 2.01 Crushingc 079 Tertiary Crusher L11 2.00 Particulate Point Source 2.01 Crushingc 080 Tertiary Crusher L12 2.00 Particulate Point Source 2.01 Crushingc 081 Tertiary Crusher L13 2.00 Particulate Point Source 2.01 Crushingc 082 Tertiary Crusher L14 2.00 Particulate Point Source 2.01 Crushingc 083 Tertiary Crusher L15 2.00 Particulate Point Source 2.01 Crushingc 084 Tertiary Crusher L16 2.00 Particulate Point Source 2.01 Crushingc 093 Secondary Crusher L6 2.00 Particulate Point Source 2.01 Crushingc 094 Secondary Crusher L7 2.00 Particulate Point Source 2.01 Crushingc 095 Secondary Crusher L8 2.00 Particulate Point Source 2.01 Crushingc 096 Secondary Crusher L9 2.00 Particulate Point Source 2.01 Crushingc 097 Secondary Crusher L10 2.00 Particulate Point Source 2.01 Crushingc 103 Secondary Crusher L5 2.00 Particulate Point Source 2.01 Crushingc 106 Secondary Crusher L11 2.00 Particulate Point Source 2.01 Crushingc 107 Secondary Crusher L12 2.00 Particulate Point Source 2.01 Crushingc 108 Secondary Crusher L13 2.00 Particulate Point Source 2.01 Crushingc 109 Secondary Crusher L14 2.00 Particulate Point Source 2.01 Crushingc 110 Secondary Crusher L15 2.00 Particulate Point Source 2.01 Crushingc 128 Tertiary Crusher L18 2.00 Particulate Point Source 2.01 Crushingc 129 Tertiary Crusher L19 2.00 Particulate Point Source 2.01 Crushingc 130 Tertiary Crusher L20 2.00 Particulate Point Source 2.01 Crushingc 131 Tertiary Crusher L21 2.00 Particulate Point Source 2.01 Crushingc 132 Tertiary Crusher L22 2.00 Particulate Point Source 2.01 Crushingc 133 Tertiary Crusher L23 2.00 Particulate Point Source 2.01 Crushingc 134 Tertiary Crusher L24 2.00 Particulate Point Source 2.01 Crushingc 135 Tertiary Crusher L25 2.00 Particulate Point Source 2.01 Crushingc 136 Tertiary Crusher L26 2.00 Particulate Point Source 2.01 Crushingc 137 Tertiary Crusher L27 2.00 Particulate Point Source 2.01 Crushingc 138 Tertiary Crusher L28 2.00 Particulate Point Source 2.01 Crushing

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ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

c 139 Tertiary Crusher L29 2.00 Particulate Point Source 2.01 Crushing

003 North Loadout Tunnel 2.00 Particulate Point Source 2.02 Material Handling - Ore006 South Loadout Tunnel 2.00 Particulate Point Source 2.02 Material Handling - Ore001 Crude Ore Unloading Pan Feeders 2.00 Particulate Point Source 2.02 Material Handling - Ore002 Crude Ore Unloading 2.00 Particulate Point Source 2.02 Material Handling - Ore004 Coarse Ore Surge Pan Feeders 2.00 Particulate Point Source 2.02 Material Handling - Ore010 Third Stage Bins Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore019 Fourth Stage Trip/Bin/Convey 2.00 Particulate Point Source 2.02 Material Handling - Ore020 Transfer House North 2.00 Particulate Point Source 2.02 Material Handling - Ore022 Transfer House South 2.00 Particulate Point Source 2.02 Material Handling - Ore023 No. 1 Rod Mill Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore024 No. 2 Rod Mill Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore025 No. 3 Rod Mill Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore026 No. 4 Rod Mill Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore027 No. 5 Rod Mill Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore001 Phase I Apron Feeder 2.00 Particulate Point Source 2.02 Material Handling - Ore002 Phase II Apron Feeder 2.00 Particulate Point Source 2.02 Material Handling - Ore003 Phase I Primary Ore Conveyor - Tail 2.00 Particulate Point Source 2.02 Material Handling - Ore004 Phase II Primary Ore Conveyor - Tail 2.00 Particulate Point Source 2.02 Material Handling - Ore005 Line No. 1 Mill Feed Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore006 Line No. 2 Mill Feed Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore007 Line No. 3 Mill Feed Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore008 Line No. 4 Mill Feed Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore009 Line No. 5 Mill Feed Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore010 Line No. 6 Mill Feed Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore011 Line No. 7 Mill Feed Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore012 Line No. 8 Mill Feed Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore013 Line No. 9 Mill Feed Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore002 Drop Onto Coarse Ore Pile Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore006 Outside Ore Transfer 2.00 Particulate Point Source 2.02 Material Handling - Ore011 Fine Ore Drop Onto Two Underfeed Belts 2.00 Particulate Point Source 2.02 Material Handling - Ore012 Fine Ore Drop Onto Intermediate Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore013 Fine Ore Drop Onto Rod Mill Bin Conveyor 2.00 Particulate Point Source 2.02 Material Handling - Ore014 Fine Ore Drop Onto Rod Mill Bin Feeder 2.00 Particulate Point Source 2.02 Material Handling - Ore015 Fine Ore Drop Into Rod Mill Bin 2.00 Particulate Point Source 2.02 Material Handling - Ore016 Fine Ore Drop Onto Internal Conveyors 2.00 Particulate Point Source 2.02 Material Handling - Ore017 Fine Ore Drop Into Rod Mills 2.00 Particulate Point Source 2.02 Material Handling - Ore

003 Conveyor Transfer - Drive house No. 1 Primary Conv 2.00 Particulate Point Source 2.02 Material Handling - Ore004 Conveyor Transfer - Drive house No. 2 Primary Conv 2.00 Particulate Point Source 2.02 Material Handling - Ore005 Conveyor Transfer - Crude Ore Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore006 Conveyor Transfer - Crude Ore Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore007 Conveyor Transfer - Crude Ore Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore008 Conveyor Transfer - Crude Ore Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore009 Conveyor Transfer - Crude Ore Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore010 Conveyor Transfer - Crude Ore Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore011 Conveyor Transfer - Crude Ore Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore012 Conveyor Transfer - Crude Ore Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore

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ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

013 Conveyor Transfer - Crude Ore Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore014 Conveyor Transfer - Crude Ore Feed 2.00 Particulate Point Source 2.02 Material Handling - Ore008 East Car Dump 2.00 Particulate Point Source 2.02 Material Handling - Ore010 Crusher Storage Bins (E) 2.00 Particulate Point Source 2.02 Material Handling - Ore016 Crushed Ore Conveyors 2.00 Particulate Point Source 2.02 Material Handling - Ore017 Crusher Line 101 2.00 Particulate Point Source 2.02 Material Handling - Ore018 Crusher Line 102 2.00 Particulate Point Source 2.02 Material Handling - Ore019 Crusher Line 103 2.00 Particulate Point Source 2.02 Material Handling - Ore020 Crusher Line 104 2.00 Particulate Point Source 2.02 Material Handling - Ore031 East Transfer Bin 2.00 Particulate Point Source 2.02 Material Handling - Ore044 East Storage Bins #101 2.00 Particulate Point Source 2.02 Material Handling - Ore045 East Storage Bins #102 2.00 Particulate Point Source 2.02 Material Handling - Ore046 East Storage Bins #103 2.00 Particulate Point Source 2.02 Material Handling - Ore047 East Storage Bins #104 2.00 Particulate Point Source 2.02 Material Handling - Ore048 East Storage Bins #105 2.00 Particulate Point Source 2.02 Material Handling - Ore049 East Storage Bins #106 2.00 Particulate Point Source 2.02 Material Handling - Ore050 East Storage Bins #107 2.00 Particulate Point Source 2.02 Material Handling - Ore051 East Storage Bins #108 2.00 Particulate Point Source 2.02 Material Handling - Ore052 East Storage Bins #109 2.00 Particulate Point Source 2.02 Material Handling - Ore053 East Storage Bins #110 2.00 Particulate Point Source 2.02 Material Handling - Ore

c 017 Step III Coarse Crusher & Lime Dump 2.00 Particulate Point Source 2.02 Material Handling - Orec 018 Step III Coarse Crusher & Lime Dump 2.00 Particulate Point Source 2.02 Material Handling - Orec 019 Step III Coarse Crusher & Lime Dump 2.00 Particulate Point Source 2.02 Material Handling - Orec 020 Step III Coarse Crusher & Lime Dump 2.00 Particulate Point Source 2.02 Material Handling - Orec 021 Step III Coarse Crusher & Lime Dump 2.00 Particulate Point Source 2.02 Material Handling - Orec 022 Step I Coarse Crusher Pan Feeders 2.00 Particulate Point Source 2.02 Material Handling - Orec 023 Step I Coarse Crusher Pan Feeders 2.00 Particulate Point Source 2.02 Material Handling - Orec 024 Step II Coarse Crusher Pan Feeders 2.00 Particulate Point Source 2.02 Material Handling - Orec 025 Step II Coarse Crusher Pan Feeders 2.00 Particulate Point Source 2.02 Material Handling - Orec 026 Step III Coarse Crusher Pan Feeders & Lime Transfe 2.00 Particulate Point Source 2.02 Material Handling - Orec 027 Step III Coarse Crusher Pan Feeders & Lime Transfe 2.00 Particulate Point Source 2.02 Material Handling - Orec 034 Conveyor Transfer 005-006 2.00 Particulate Point Source 2.02 Material Handling - Orec 035 Conveyor Transfer 005-006 2.00 Particulate Point Source 2.02 Material Handling - Orec 036 Conveyor Transfer 010-001 2.00 Particulate Point Source 2.02 Material Handling - Orec 037 Conveyor Transfer 010-001 2.00 Particulate Point Source 2.02 Material Handling - Orec 038 Conveyor Transfer 010-001 2.00 Particulate Point Source 2.02 Material Handling - Orec 039 Conveyor Transfer 010-001 2.00 Particulate Point Source 2.02 Material Handling - Orec 040 Conveyor Transfer 005-006 2.00 Particulate Point Source 2.02 Material Handling - Orec 041 Conveyor Transfer 004-005 2.00 Particulate Point Source 2.02 Material Handling - Orec 042 Conveyor Transfer 004-005 2.00 Particulate Point Source 2.02 Material Handling - Orec 043 Conveyor Transfer 004-005 2.00 Particulate Point Source 2.02 Material Handling - Orec 044 Conveyor Transfer 004-005 2.00 Particulate Point Source 2.02 Material Handling - Orec 045 Conveyor Transfer 004-005 2.00 Particulate Point Source 2.02 Material Handling - Orec 046 Conveyor Transfer 004-005 2.00 Particulate Point Source 2.02 Material Handling - Orec 047 Conveyor Transfer 011-02/03 2.00 Particulate Point Source 2.02 Material Handling - Orec 048 Surge Pile/Reclaim 011-01 2.00 Particulate Point Source 2.02 Material Handling - Orec 052 Conveyor Transfer 008-009 2.00 Particulate Point Source 2.02 Material Handling - Ore

Task 2A\BART Survey Data Sorted.xls

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ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

c 053 Conveyor Transfer 008-009 2.00 Particulate Point Source 2.02 Material Handling - Orec 058 Conveyor Transfer 005 to 006 2.00 Particulate Point Source 2.02 Material Handling - Orec 059 Conveyor Transfer 005 to 006 2.00 Particulate Point Source 2.02 Material Handling - Orec 060 Conveyor Transfer 005 to 006 2.00 Particulate Point Source 2.02 Material Handling - Orec 061 Conveyor Transfer 003 to 004 2.00 Particulate Point Source 2.02 Material Handling - Orec 062 Conveyor Transfer 003 to 004 2.00 Particulate Point Source 2.02 Material Handling - Orec 063 Conveyor Transfer 003 to 004 2.00 Particulate Point Source 2.02 Material Handling - Orec 064 Conveyor Transfer 003 to 004 2.00 Particulate Point Source 2.02 Material Handling - Orec 065 Tertiary Storage Bin 1-4 2.00 Particulate Point Source 2.02 Material Handling - Orec 066 Tertiary Storage Bin 1-4 2.00 Particulate Point Source 2.02 Material Handling - Orec 067 Tertiary Storage Bin 1-4 2.00 Particulate Point Source 2.02 Material Handling - Orec 068 Tertiary Storage Bin 1-4 2.00 Particulate Point Source 2.02 Material Handling - Orec 085 Tertiary Crusher 080 Bins 5-8 2.00 Particulate Point Source 2.02 Material Handling - Orec 086 Tertiary Crusher 080 Bins 5-8 2.00 Particulate Point Source 2.02 Material Handling - Orec 087 Tertiary Crusher 080 Bins 5-8 2.00 Particulate Point Source 2.02 Material Handling - Orec 088 Tertiary Crusher 080 Bins 5-8 2.00 Particulate Point Source 2.02 Material Handling - Orec 089 Tertiary Crusher 080 Bins 5-8 2.00 Particulate Point Source 2.02 Material Handling - Orec 090 Tertiary Crusher 080 Bins 5-8 2.00 Particulate Point Source 2.02 Material Handling - Orec 091 Tertiary Crusher 080 Bins 5-8 2.00 Particulate Point Source 2.02 Material Handling - Orec 092 Tertiary Crusher 080 Bins 5-8 2.00 Particulate Point Source 2.02 Material Handling - Orec 098 Conveyor Transfer 008 to 009 2.00 Particulate Point Source 2.02 Material Handling - Orec 099 Conveyor Transfer 008 to 009 2.00 Particulate Point Source 2.02 Material Handling - Orec 100 Conveyor Transfer 008 to 009 2.00 Particulate Point Source 2.02 Material Handling - Orec 101 Conveyor Transfer 008 to 009 2.00 Particulate Point Source 2.02 Material Handling - Orec 102 Storage Bin 070-02 2.00 Particulate Point Source 2.02 Material Handling - Orec 104 Conveyor Transfer 008 to 009 2.00 Particulate Point Source 2.02 Material Handling - Orec 105 Conveyor Transfer 008 to 009 2.00 Particulate Point Source 2.02 Material Handling - Orec 111 Conveyor Transfer 001-070 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 112 Conveyor Transfer 003 2.00 Particulate Point Source 2.02 Material Handling - Orec 113 Conveyor Transfer 003 2.00 Particulate Point Source 2.02 Material Handling - Orec 114 Conveyor Transfer 003-004 2.00 Particulate Point Source 2.02 Material Handling - Orec 115 Conveyor Transfer 003-004 2.00 Particulate Point Source 2.02 Material Handling - Orec 116 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 117 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 118 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 119 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 120 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 121 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 122 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 123 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 124 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 125 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 126 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 127 Tertiary Storage 006-080 Bin 2.00 Particulate Point Source 2.02 Material Handling - Orec 140 Conveyor Transfer 005-006 2.00 Particulate Point Source 2.02 Material Handling - Orec 141 Conveyor Transfer 005-006 2.00 Particulate Point Source 2.02 Material Handling - Orec 144 Conveyor Transfer 009-020 2.00 Particulate Point Source 2.02 Material Handling - Ore

Task 2A\BART Survey Data Sorted.xls

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ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

c 145 Conveyor Transfer 009-020 2.00 Particulate Point Source 2.02 Material Handling - Orec 146 Conveyor Transfer 009-020 2.00 Particulate Point Source 2.02 Material Handling - Orec 147 Conveyor Transfer 009-020 2.00 Particulate Point Source 2.02 Material Handling - Orec 148 Storage Bin L1,2 2.00 Particulate Point Source 2.02 Material Handling - Orec 149 Storage Bin L1,2 2.00 Particulate Point Source 2.02 Material Handling - Orec 150 Storage Bin L1,2 2.00 Particulate Point Source 2.02 Material Handling - Orec 151 Storage Bin L1,2 2.00 Particulate Point Source 2.02 Material Handling - Orec 152 Storage Bin L1,2 2.00 Particulate Point Source 2.02 Material Handling - Orec 153 Storage Bin L1,2 2.00 Particulate Point Source 2.02 Material Handling - Orec 154 Storage Bin L1,2 2.00 Particulate Point Source 2.02 Material Handling - Orec 155 Storage Bin L3,4 2.00 Particulate Point Source 2.02 Material Handling - Orec 156 Storage Bin L3,4 2.00 Particulate Point Source 2.02 Material Handling - Orec 157 Storage Bin L3,4 2.00 Particulate Point Source 2.02 Material Handling - Orec 158 Storage Bin L3,4 2.00 Particulate Point Source 2.02 Material Handling - Orec 159 Storage Bin L3,4 2.00 Particulate Point Source 2.02 Material Handling - Orec 160 Storage Bin L3,4 2.00 Particulate Point Source 2.02 Material Handling - Orec 161 Storage Bin L3,4 2.00 Particulate Point Source 2.02 Material Handling - Orec 162 Storage Bin L5,6 2.00 Particulate Point Source 2.02 Material Handling - Orec 163 Storage Bin L5,6 2.00 Particulate Point Source 2.02 Material Handling - Orec 164 Storage Bin L5,6 2.00 Particulate Point Source 2.02 Material Handling - Orec 165 Storage Bin L5,6 2.00 Particulate Point Source 2.02 Material Handling - Orec 166 Storage Bin L5,6 2.00 Particulate Point Source 2.02 Material Handling - Orec 167 Storage Bin L5,6 2.00 Particulate Point Source 2.02 Material Handling - Orec 168 Storage Bin L5,6 2.00 Particulate Point Source 2.02 Material Handling - Orec 169 Storage Bin L7,8 2.00 Particulate Point Source 2.02 Material Handling - Orec 170 Storage Bin L7,8 2.00 Particulate Point Source 2.02 Material Handling - Orec 171 Storage Bin L7,8 2.00 Particulate Point Source 2.02 Material Handling - Orec 172 Storage Bin L7,8 2.00 Particulate Point Source 2.02 Material Handling - Orec 173 Storage Bin L7,8 2.00 Particulate Point Source 2.02 Material Handling - Orec 174 Storage Bin L7,8 2.00 Particulate Point Source 2.02 Material Handling - Orec 175 Storage Bin L7,8 2.00 Particulate Point Source 2.02 Material Handling - Orec 176 Storage Bin L9,10 2.00 Particulate Point Source 2.02 Material Handling - Orec 177 Storage Bin L9,10 2.00 Particulate Point Source 2.02 Material Handling - Orec 178 Storage Bin L9,10 2.00 Particulate Point Source 2.02 Material Handling - Orec 179 Storage Bin L9,10 2.00 Particulate Point Source 2.02 Material Handling - Orec 180 Storage Bin L9,10 2.00 Particulate Point Source 2.02 Material Handling - Orec 181 Storage Bin L9,10 2.00 Particulate Point Source 2.02 Material Handling - Orec 182 Storage Bin L9,10 2.00 Particulate Point Source 2.02 Material Handling - Orec 183 Storage Bin L11,12 2.00 Particulate Point Source 2.02 Material Handling - Orec 184 Storage Bin L11,12 2.00 Particulate Point Source 2.02 Material Handling - Orec 185 Storage Bin L11,12 2.00 Particulate Point Source 2.02 Material Handling - Orec 186 Storage Bin L11,12 2.00 Particulate Point Source 2.02 Material Handling - Orec 187 Storage Bin L11,12 2.00 Particulate Point Source 2.02 Material Handling - Orec 188 Storage Bin L11,12 2.00 Particulate Point Source 2.02 Material Handling - Orec 189 Storage Bin L11,12 2.00 Particulate Point Source 2.02 Material Handling - Orec 190 Conveyor Transfer 009-020 2.00 Particulate Point Source 2.02 Material Handling - Orec 191 Conveyor Transfer 009-020 2.00 Particulate Point Source 2.02 Material Handling - Ore

Task 2A\BART Survey Data Sorted.xls

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ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

c 192 Conveyor Transfer 009-020 2.00 Particulate Point Source 2.02 Material Handling - Orec 193 Conveyor Transfer 009-020 2.00 Particulate Point Source 2.02 Material Handling - Orec 194 Storage Bin L13,14 2.00 Particulate Point Source 2.02 Material Handling - Orec 195 Storage Bin L13,14 2.00 Particulate Point Source 2.02 Material Handling - Orec 196 Storage Bin L13,14 2.00 Particulate Point Source 2.02 Material Handling - Orec 197 Storage Bin L13,14 2.00 Particulate Point Source 2.02 Material Handling - Orec 198 Storage Bin L13,14 2.00 Particulate Point Source 2.02 Material Handling - Orec 199 Storage Bin L13,14 2.00 Particulate Point Source 2.02 Material Handling - Orec 200 Storage Bin L13,14 2.00 Particulate Point Source 2.02 Material Handling - Orec 201 Storage Bin L15,16 2.00 Particulate Point Source 2.02 Material Handling - Orec 202 Storage Bin L15,16 2.00 Particulate Point Source 2.02 Material Handling - Orec 203 Storage Bin L15,16 2.00 Particulate Point Source 2.02 Material Handling - Orec 204 Storage Bin L15,16 2.00 Particulate Point Source 2.02 Material Handling - Orec 205 Storage Bin L15,16 2.00 Particulate Point Source 2.02 Material Handling - Orec 206 Storage Bin L15,16 2.00 Particulate Point Source 2.02 Material Handling - Orec 207 Storage Bin L15,16 2.00 Particulate Point Source 2.02 Material Handling - Orec 208 Storage Bin L17,18 2.00 Particulate Point Source 2.02 Material Handling - Orec 209 Storage Bin L17,18 2.00 Particulate Point Source 2.02 Material Handling - Orec 210 Storage Bin L17,18 2.00 Particulate Point Source 2.02 Material Handling - Orec 211 Storage Bin L17,18 2.00 Particulate Point Source 2.02 Material Handling - Orec 212 Storage Bin L17,18 2.00 Particulate Point Source 2.02 Material Handling - Orec 213 Storage Bin L17,18 2.00 Particulate Point Source 2.02 Material Handling - Orec 214 Storage Bin L17,18 2.00 Particulate Point Source 2.02 Material Handling - Ore

028 Limestone/Soda Ash Storage Bins 2.00 Particulate Point Source 2.03 Material Handling - Additive029 Additive Unloading 2.00 Particulate Point Source 2.03 Material Handling - Additive030 Line 2 Additive Storage Bins 2.00 Particulate Point Source 2.03 Material Handling - Additive031 Line 2 Additive Addition 2.00 Particulate Point Source 2.03 Material Handling - Additive032 Soda Ash/Binder Mixing 2.00 Particulate Point Source 2.03 Material Handling - Additive057 Soda Ash/Binder Day Bin 1 2.00 Particulate Point Source 2.03 Material Handling - Additive058 Soda Ash/Binder Addition 2.00 Particulate Point Source 2.03 Material Handling - Additive062 Soda Ash/Binder Day Bin 2 2.00 Particulate Point Source 2.03 Material Handling - Additive016 Phase I Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additive017 Phase II Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additive028 Bentonite Storage Silo - East 2.00 Particulate Point Source 2.03 Material Handling - Additive029 Bentonite Storage Silo - West 2.00 Particulate Point Source 2.03 Material Handling - Additive018 Binder Transfer to Storage Silo 2.00 Particulate Point Source 2.03 Material Handling - Additive019 Binder Transfer to Binder Shift Bins 2.00 Particulate Point Source 2.03 Material Handling - Additive020 Binder Blending 2.00 Particulate Point Source 2.03 Material Handling - Additive

015 Additive Blending, Phase I 2.00 Particulate Point Source 2.03 Material Handling - Additive016 Additive Blending, Phase II 2.00 Particulate Point Source 2.03 Material Handling - Additive017 Addititive Silo, Phase I 2.00 Particulate Point Source 2.03 Material Handling - Additive018 Addititive Silo, Phase II 2.00 Particulate Point Source 2.03 Material Handling - Additive077 E Addititive Blending 2.00 Particulate Point Source 2.03 Material Handling - Additive078 E Addititive Blending 2.00 Particulate Point Source 2.03 Material Handling - Additive079 E Addititive Blending 2.00 Particulate Point Source 2.03 Material Handling - Additive080 E Addititive Blending 2.00 Particulate Point Source 2.03 Material Handling - Additive081 E Additive Bins 3-4 2.00 Particulate Point Source 2.03 Material Handling - Additive

Task 2A\BART Survey Data Sorted.xls

Page 7 of 14 Print Date: 3/19/2003
ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

082 E Additive Bins 5-6 2.00 Particulate Point Source 2.03 Material Handling - Additive083 E Additive Unload 2.00 Particulate Point Source 2.03 Material Handling - Additive084 E Additive Unload 2.00 Particulate Point Source 2.03 Material Handling - Additive

c 217 L3 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 218 L3 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 219 L3 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 220 L3 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 236 S1 Bentonite Storage Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 237 S1 Bentonite Storage Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 238 S1 Bentonite Storage Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 239 L2,3 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 240 L2,3 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 241 L2,3 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 242 L2,3 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 243 S1,2 Bentonite Unloading 2.00 Particulate Point Source 2.03 Material Handling - Additivec 244 S2 Bentonite Storage Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 245 S2 Bentonite Storage Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 246 S2 Bentonite Storage Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 247 L4 Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additivec 248 L4 Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additivec 249 L4 Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additivec 250 L4 Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additivec 251 L4 Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additivec 252 L4 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 253 L4 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 254 L4 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 255 L4 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 256 L4 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 268 L5 Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additivec 269 L5 Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additivec 270 L5 Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additivec 271 L5 Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additivec 272 L5 Bentonite Day Bins 2.00 Particulate Point Source 2.03 Material Handling - Additivec 273 L5 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 274 L5 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 275 L5 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 276 L5 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 277 L5 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 297 S3 Bentonite Storage 2.00 Particulate Point Source 2.03 Material Handling - Additivec 298 S3 Bentonite Storage 2.00 Particulate Point Source 2.03 Material Handling - Additivec 299 S3 Bentonite Storage 2.00 Particulate Point Source 2.03 Material Handling - Additivec 300 S3 Bentonite Storage 2.00 Particulate Point Source 2.03 Material Handling - Additivec 301 L6 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 302 L6 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 303 L6 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 304 L6 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 305 L6 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additive

Task 2A\BART Survey Data Sorted.xls

Page 8 of 14 Print Date: 3/19/2003
ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

c 306 L6 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 307 L6 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 308 L6 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 309 L6 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 310 L6 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 320 L7 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 321 L7 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 322 L7 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 323 L7 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 324 L7 Bentonite Day Bin 2.00 Particulate Point Source 2.03 Material Handling - Additivec 325 L7 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 326 L7 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 327 L7 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 328 L7 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 329 L7 Bentonite Blending 2.00 Particulate Point Source 2.03 Material Handling - Additivec 367 Coal Unloading Silo 2.00 Particulate Point Source 2.04 Material Handling - Coalc 368 Coal Unloading Silo 2.00 Particulate Point Source 2.04 Material Handling - Coalc 369 Coal Unloading Silo 2.00 Particulate Point Source 2.04 Material Handling - Coalc 370 Coal Unloading Silo 2.00 Particulate Point Source 2.04 Material Handling - Coalc 371 Coal Unloading Silo 2.00 Particulate Point Source 2.04 Material Handling - Coalc 372 Coal Unloading Silo 2.00 Particulate Point Source 2.04 Material Handling - Coalc 373 Coal Unloading Silo 2.00 Particulate Point Source 2.04 Material Handling - Coalc 374 Coal Day Bin/Conveyor Transfer 2.00 Particulate Point Source 2.04 Material Handling - Coalc 375 Coal Day Bin/Conveyor Transfer 2.00 Particulate Point Source 2.04 Material Handling - Coalc 376 Coal Day Bin/Conveyor Transfer 2.00 Particulate Point Source 2.04 Material Handling - Coalc 377 Coal Day Bin/Conveyor Transfer 2.00 Particulate Point Source 2.04 Material Handling - Coalc 378 Coal Day Bin/Conveyor Transfer 2.00 Particulate Point Source 2.04 Material Handling - Coalc 379 Coal Day Bin/Conveyor Transfer 2.00 Particulate Point Source 2.04 Material Handling - Coalc 380 Coal Day Bin/Conveyor Transfer 2.00 Particulate Point Source 2.04 Material Handling - Coalc 381 Coal Day Bin/Conveyor Transfer 2.00 Particulate Point Source 2.04 Material Handling - Coalc 382 Coal Day Bin/Conveyor Transfer 2.00 Particulate Point Source 2.04 Material Handling - Coal

023 Grate Feed 2.00 Particulate Point Source 2.05 Straight Grate (Grate)023 Pellet Machine Discharge Line No 1 2.00 Particulate Point Source 2.06 Straight Grate (Pellet Discharge)024 Pellet Machine Discharge Line No 2 2.00 Particulate Point Source 2.06 Straight Grate (Pellet Discharge)025 Pellet Machine Discharge Line No 3 2.00 Particulate Point Source 2.06 Straight Grate (Pellet Discharge)027 Machine Discharge 2.00 Particulate Point Source 2.06 Straight Grate (Pellet Discharge)033 Line 2 Grate Feed 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)034 Line 2 Grate Discharge 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)037 Line 1 Grate Feed 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)038 Line 1 Grate Discharge 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)

c 221 L3 Grate Feed 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)c 222 L3 Grate Discharge 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)c 257 L4 Grate Feed 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)c 258 L4 Grate Discharge 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)c 278 L5 Grate Feed 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)c 279 L5 Grate Discharge 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)c 311 L6 Grate Feed 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)

Task 2A\BART Survey Data Sorted.xls

Page 9 of 14 Print Date: 3/19/2003
ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

c 312 L6 Grate Discharge 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)c 330 L7 Grate Feed 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)c 331 L7 Grate Discharge 2.00 Particulate Point Source 2.07 Grate-Kiln (Grate)

035 Line 2 Kiln Cooler Discharge & Vibrating Feeders 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)036 Line 2 Pellet Cooler Exhaust 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)041 Line 1 Pellet Cooler Exhaust 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)

025 Pellet Cooler, Phase I 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)026 Pellet Cooler, Phase II 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)

c 226 L3 Pellet Cooler Secondary Air 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)c 227 L3 Cooler Vent Stack 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)c 228 L3 Cooler Discharge 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)c 262 L4 Pellet Cooler Secondary Air 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)c 263 L4 Pellet Cooler Vent Stack 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)c 283 L5 Pellet Cooler Secondary Air 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)c 284 L5 Pellet Cooler Vent Stack 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)c 316 L6 Pellet Cooler Secondary Air 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)c 317 L6 Pellet Cooler Vent 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)c 335 L7 Pellet Cooler Secondary Air 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)c 336 L7 Pellet Cooler Vent 2.00 Particulate Point Source 2.08 Grate-Kiln (Cooler)

023 Cooler Dump Zone, Phase I 2.00 Particulate Point Source 2.09 Grate-Kiln (Pellet Discharge)

c 265 L4 Cooler Discharge 2.00 Particulate Point Source 2.09 Grate-Kiln (Pellet Discharge)c 286 L5 Cooler Discharge 2.00 Particulate Point Source 2.09 Grate-Kiln (Pellet Discharge)

104 Conveyor 22S 2.00 Particulate Point Source 2.10 Material Handling - Pellets105 Conveyor 22N 2.00 Particulate Point Source 2.10 Material Handling - Pellets106 Conveyor 23S 2.00 Particulate Point Source 2.10 Material Handling - Pellets107 Conveyor 23N 2.00 Particulate Point Source 2.10 Material Handling - Pellets018 Phase I Hearth Layer Bin/Layer Feed 2.00 Particulate Point Source 2.10 Material Handling - Pellets019 Phase II Hearth Layer Bin/Layer Feed 2.00 Particulate Point Source 2.10 Material Handling - Pellets026 Pellet Hearth Layer Screening 2.00 Particulate Point Source 2.10 Material Handling - Pellets027 Pellet Transfer House 2.00 Particulate Point Source 2.10 Material Handling - Pellets021 Pellet Drop Onto Internal Hearth Layer Conveyor 2.00 Particulate Point Source 2.10 Material Handling - Pellets022 Drop Into Hearth Layer Bin 2.00 Particulate Point Source 2.10 Material Handling - Pellets024 Drop Into Hearth Layer Screen 2.00 Particulate Point Source 2.10 Material Handling - Pellets025 Drop Onto Conveyor to Hearth Layer Bin 2.00 Particulate Point Source 2.10 Material Handling - Pellets028 Drop Onto Conveyor to Pellet Splitter Bin 2.00 Particulate Point Source 2.10 Material Handling - Pellets029 Drop Into Pellet Splitter Bin 2.00 Particulate Point Source 2.10 Material Handling - Pellets030 Drop Onto Product Splitter Bin Conveyors 2.00 Particulate Point Source 2.10 Material Handling - Pellets031 Drop Into P1-P2 Transfer House 2.00 Particulate Point Source 2.10 Material Handling - Pellets032 Drop Onto P3 Pellet Pile Underfeed Conveyor 2.00 Particulate Point Source 2.10 Material Handling - Pellets

028 Pellet Product Conveyor - Phase I 2.00 Particulate Point Source 2.10 Material Handling - Pellets032 Product Belts, Phase II 2.00 Particulate Point Source 2.10 Material Handling - Pellets034 Conveyor Transfer - Pellet Pile to Loadout Conveyo 2.00 Particulate Point Source 2.10 Material Handling - Pellets

c 229 L3 Feeder 041/046 Belts 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 230 L3 041/046 Conveyor Belt Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 231 L3 041/046 Conveyor Belt Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 232 S1 Conveyor Transfer 042-043 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 233 S1 Conveyor Transfer 042-043 2.00 Particulate Point Source 2.10 Material Handling - Pellets

Task 2A\BART Survey Data Sorted.xls

Page 10 of 14 Print Date: 3/19/2003
ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

c 234 L1 Conveyor Transfer 041-043 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 235 L1 Conveyor Transfer 041-043 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 264 L4 Conveyor Transfer Feeder 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 266 L4 Conveyor Transfer 041/046 to 042 Belts 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 267 L4 Conveyor Transfer 041/046 to 042 Belts 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 285 L5 Conveyor Transfer Feeder 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 287 L5 Conveyor Transfer Belts 041/046 to 042 Belts 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 288 L5 Conveyor Transfer Belts 041/046 to 042 Belts 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 289 Step I 043 Conveyor Vents 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 290 Step I 043 Conveyor Vents 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 291 Step I 043 Conveyor Vents 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 292 Step I 043 Conveyor Vents 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 293 Step I 043 Conveyor Vents 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 294 Step I 043 Conveyor Vents 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 295 S3 Conveyor Transfer 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 296 S3 Conveyor Transfer 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 318 L6 Conveyor Transfer 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 319 L6 Conveyor Transfer 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 337 L7 Conveyor Transfer 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 338 L7 Conveyor Transfer 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 339 Step I 043/044 Conveyor Transfer 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 340 Step I 043/044 Conveyor Transfer 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 341 Step III 042 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 342 Step III 042 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 343 Step III 043 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 344 Step III 043 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 345 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 346 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 347 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 348 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 349 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 350 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 351 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 352 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 353 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 354 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pelletsc 355 Step III 044 Conveyor Vent 2.00 Particulate Point Source 2.10 Material Handling - Pellets

Task 2A\BART Survey Data Sorted.xls

Page 11 of 14 Print Date: 3/19/2003
ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

052 Paint Gun 3 2.00 Particulate Point Source 2.11 Paint Gun053 Paint Gun 4 2.00 Particulate Point Source 2.11 Paint Gun054 Paint Gun 5 2.00 Particulate Point Source 2.11 Paint Gun055 Paint Gun 6 2.00 Particulate Point Source 2.11 Paint Gun056 Paint Gun 7 2.00 Particulate Point Source 2.11 Paint Gun024 Cooler Vibrating Feeder - Phase II 2.00 Particulate Point Source Uncategorized027 Cooler Vibrating Feeder - Phase I 2.00 Particulate Point Source Uncategorized

c 260 L4 Recoup System Air 2.00 Particulate Point Source Uncategorizedc 281 L5 Recoup Air System 2.00 Particulate Point Source Uncategorizedc 314 L6 Recoup Air System 2.00 Particulate Point Source Uncategorizedc 333 L7 Recoup Air System 2.00 Particulate Point Source Uncategorized

120 Furnace 11 Discharge 3.00 Induration Point Source 2.06 Straight Grate (Pellet Discharge)121 Furnace 12 Discharge 3.00 Induration Point Source 2.06 Straight Grate (Pellet Discharge)019 Grate Kiln - Grate Feed, Phase I 3.00 Induration Point Source 2.07 Grate-Kiln (Grate)020 Grate Kiln - Grate Feed, Phase II 3.00 Induration Point Source 2.07 Grate-Kiln (Grate)021 Grate Kiln - Grate Discharge, Phase I 3.00 Induration Point Source 2.07 Grate-Kiln (Grate)022 Grate Kiln - Grate Discharge, Phase II 3.00 Induration Point Source 2.07 Grate-Kiln (Grate)

c 223 L3 Traveling Grate 3.00 Induration Point Source 2.07 Grate-Kiln (Grate)c 259 L4 Traveling Grate 3.00 Induration Point Source 2.07 Grate-Kiln (Grate)c 280 L5 Traveling Grate 3.00 Induration Point Source 2.07 Grate-Kiln (Grate)c 313 L6 Traveling Grate 3.00 Induration Point Source 2.07 Grate-Kiln (Grate)c 332 L7 Traveling Grate 3.00 Induration Point Source 2.07 Grate-Kiln (Grate)

039 Line 1 Kiln Cooler Discharge 3.00 Induration Point Source 2.09 Grate-Kiln (Pellet Discharge)020 Pellet Indurating Furnace Line No 1 3.00 Induration Point Source 3.01 Straight Grate (Induration)021 Pellet Indurating Furnace Line No 2 3.00 Induration Point Source 3.01 Straight Grate (Induration)022 Pellet Indurating Furnace Line No 3 3.00 Induration Point Source 3.01 Straight Grate (Induration)026 Indurating Machine 3.00 Induration Point Source 3.01 Straight Grate (Induration)

100 Furnace 11 Hood Exhaust 3.00 Induration Point Source 3.01 Straight Grate (Induration)104 Furnace 12 Hood Exhaust 3.00 Induration Point Source 3.01 Straight Grate (Induration)

040 Line 1 Pellet Induration 3.00 Induration Point Source 3.02 Grate-Kiln (Induration)042 Line 2 Pellet Induration 3.00 Induration Point Source 3.02 Grate-Kiln (Induration)

029 Grate Kiln - Indurator Waste Gas, Phase I 3.00 Induration Point Source 3.02 Grate-Kiln (Induration)030 Grate Kiln - Indurator Waste Gas, Phase II 3.00 Induration Point Source 3.02 Grate-Kiln (Induration)031 Grate Kiln - Indurator Waste Gas, Phase II 3.00 Induration Point Source 3.02 Grate-Kiln (Induration)

c 225 L3 Rotary Kiln 3.00 Induration Point Source 3.02 Grate-Kiln (Induration)c 261 L4 Rotary Kiln 3.00 Induration Point Source 3.02 Grate-Kiln (Induration)c 282 L5 Rotary Kiln 3.00 Induration Point Source 3.02 Grate-Kiln (Induration)c 315 L6 Rotary Kiln 3.00 Induration Point Source 3.02 Grate-Kiln (Induration)c 334 L7 Rotary Kiln 3.00 Induration Point Source 3.02 Grate-Kiln (Induration)

002 Power Boiler 2 4.00 External Combustion Source 4.01 Boiler (Electrical Generator)

008 Boiler 11 (South Crusher Bldg) 4.00 External Combustion Source 4.02 Boiler009 Boiler 4 (North Crusher Bldg) 4.00 External Combustion Source 4.02 Boiler011 Boiler 2 (North Maint. Bldg) 4.00 External Combustion Source 4.02 Boiler012 Boiler 3 (North Maint. Bldg) 4.00 External Combustion Source 4.02 Boiler013 Boiler 12 (South Crusher Bldg) 4.00 External Combustion Source 4.02 Boiler051 Fairlane Truck Shop Boiler 4.00 External Combustion Source 4.02 Boiler052 Fairlane New Shop Boiler 4.00 External Combustion Source 4.02 Boiler

Task 2A\BART Survey Data Sorted.xls

Page 12 of 14 Print Date: 3/19/2003
ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

053 Fuel Handling Boiler #1 4.00 External Combustion Source 4.02 Boiler054 Fuel Handling Boiler #2 4.00 External Combustion Source 4.02 Boiler

003 Unit #3 Boiler 4.00 External Combustion Source 4.02 Boiler

003 Process Boiler 1 4.00 External Combustion Source 4.02 Boiler004 Process Boiler 2 4.00 External Combustion Source 4.02 Boiler

c 001 SI 104 MMBtu Heating Boiler 4.00 External Combustion Source 4.02 Boilerc 002 SI 104 MMBtu Heating Boiler 4.00 External Combustion Source 4.02 Boilerc 003 SII 125 MMBtu Heating Boiler 4.00 External Combustion Source 4.02 Boilerc 004 SIII 153 MMBtu Heating Boiler 4.00 External Combustion Source 4.02 Boilerc 005 SIII 153 MMBtu Heating Boiler 4.00 External Combustion Source 4.02 Boilerc 010 24.60 MMBtu Boiler 4.00 External Combustion Source 4.02 Boilerc 011 24.60 MMBtu Boiler 4.00 External Combustion Source 4.02 Boiler

099 10 Makeup Heaters (F. Crusher Bldg) 4.00 External Combustion Source 4.03 Heater (Make-up)

c 028 Zinc Melt Furnace 4.00 External Combustion Source 4.04 Zinc Melt Furnacec 029 Zinc Melt Furnace 4.00 External Combustion Source 4.04 Zinc Melt Furnacec 030 Zinc Melt Furnace 4.00 External Combustion Source 4.04 Zinc Melt Furnacec 031 Zinc Melt Furnace 4.00 External Combustion Source 4.04 Zinc Melt Furnacec 032 Zinc Melt Furnace 4.00 External Combustion Source 4.04 Zinc Melt Furnacec 033 Zinc Melt Furnace 4.00 External Combustion Source 4.04 Zinc Melt Furnacec 142 Zinc Melt Furnace 4.00 External Combustion Source 4.04 Zinc Melt Furnacec 143 Zinc Melt Furnace 4.00 External Combustion Source 4.04 Zinc Melt Furnacec 006 Diesel Generator 5.00 Internal Combustion Source 5.01 Diesel Enginec 007 Diesel Generator 5.00 Internal Combustion Source 5.01 Diesel Enginec 008 Diesel Generator 5.00 Internal Combustion Source 5.01 Diesel Enginec 009 Diesel Fire Pump 5.00 Internal Combustion Source 5.01 Diesel Enginec 012 Diesel Generator 5.00 Internal Combustion Source 5.01 Diesel Enginec 051 Diesel Generator 5.00 Internal Combustion Source 5.01 Diesel Enginec 215 Diesel Generator 5.00 Internal Combustion Source 5.01 Diesel Enginec 383 Diesel Generator 5.00 Internal Combustion Source 5.01 Diesel Enginec 384 Diesel Generator 5.00 Internal Combustion Source 5.01 Diesel Enginec 385 Diesel Generator 5.00 Internal Combustion Source 5.01 Diesel Enginec 386 Diesel Generator 5.00 Internal Combustion Source 5.01 Diesel Enginec 387 Air Compressor 5.00 Internal Combustion Source Uncategorized

Task 2A\BART Survey Data Sorted.xls

Page 13 of 14 Print Date: 3/19/2003
ATION

EMISSION 

UNIT ID (2) EMISSION UNIT DESCRIPTION Primary Source Type Secondary Source Type

Preliminary Categorization of BART-Eligible Sources at MN Taconite Plants

NEI, please specify. Primary Source Type Secondary Source Type

1.00 Particulate Fugitive Source 1.01 Unpaved Roads

1.02 Material Handling (Conveyor)1.03 Material Handling (Mobile Equipment)1.04 Material Handling (Other)1.03 Wind Erosion (Stockpile)1.04 Wind Erosion (Other)

2.00 Particulate Point Source 2.01 Crushing

2.02 Material Handling - Ore2.03 Material Handling - Additive2.04 Material Handling - Coal2.05 Straight Grate (Grate)2.06 Straight Grate (Pellet Discharge)2.07 Grate-Kiln (Grate)2.08 Grate-Kiln (Cooler)2.09 Grate-Kiln (Pellet Discharge)2.10 Material Handling - Pellets2.11 Paint Gun

3.00 Induration Point Source 3.01 Straight Grate (Induration)

3.02 Grate-Kiln (Induration)

4.00 External Combustion Source 4.01 Boiler (Electrical Generator)

4.02 Boiler4.03 Heater (Make-up)4.04 Zinc Melt Furnace

5.00 Internal Combustion Source 5.01 Diesel EngineUncategorized Uncategorized

Task 2A\BART Survey Data Sorted.xls

Page 14 of 14 Print Date: 3/19/2003

TACONITE BART ASSISTANCE TO MPCA 

AFFORDABILITY OF CONTROLS 

March 18, 2003 

1. Prepare summary of the general industry financial condition and foreign competition 

• Use documented publicly available information 

• Consider other topics identified by industry and that industry will provide supporting 

data/information to summarize 

 Objective: provide qualitative analysis of the ramifications of cost increases to the industry 

2. Develop a cost table for taconite producer and MPCA use in the future 

• BART alternative capital costs (annualized cost) 

• Increase in compliance demonstration costs due to BART alternative 

• Pass through costs (power, diesel fuel cost increases due to BART) 

• Sum total cost and production cost increase for an individual BART alternative 

• Develop $/ton cost increase due to BART alternative 

 Objective: provide for the documentation of cost increases to industry for each BART 

 alternative evaluated 

 

3. Summarize potential power and diesel fuel cost increases due to BART for taconite 

producer and MPCA use in the future 

• Interview primary power and diesel fuel providers regarding BART alternatives considered 

for them, product cost increases, and ability to increase product costs 

Objective: first cut evaluation of “pass through costs” for future update by industry and MPCA 
ATTACHMENT D 

July 1, 1999, Federal Register Notice – Regional Haze Regulations; Final 

Rule
federal register

Thursday

July 1, 1999

Part II

Environmental

Protection Agency

40 CFR Part 51

Regional Haze Regulations; Final Rule
35714 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Part 51

[FRL–6353–4]

RIN 2060–AF32

[Docket No A–95–38]

Regional Haze Regulations

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Final rule.

SUMMARY: Section 169A of the Clean Air

Act (CAA) sets forth a national goal for

visibility which is the ‘‘prevention of

any future, and the remedying of any

existing, impairment of visibility in

Class I areas which impairment results

from manmade air pollution.’’ There are

156 Class I areas across the country,

including many well-known national

parks and wilderness areas, such as the

Grand Canyon, Great Smokies,

Shenandoah, Yellowstone, Yosemite,

the Everglades, and the Boundary

Waters. Regional haze is visibility

impairment caused by the cumulative

air pollutant emissions from numerous

sources over a wide geographic area.

The EPA promulgated regulations in

1980 to address visibility impairment

that is ‘‘reasonably attributable’’ to one

or a small group of sources, but EPA

deferred action on regional haze

regulations until monitoring, modeling,

and scientific knowledge about the

relationship between pollutants and

visibility effects improved. In 1993, the

National Academy of Sciences (NAS)

concluded that ‘‘current scientific

knowledge is adequate and control

technologies are available for taking

regulatory action to improve and protect

visibility.’’

On July 31, 1997 (62 FR 41138), EPA

published proposed amendments to the

1980 regulations to set forth a program

to address regional haze visibility

impairment. The EPA also published a

notice of availability of additional

information on the proposed regional

haze regulation on September 3, 1998.

This notice took comment specifically

on new implementation plan timelines

set forth in the Transportation Equity

Act for the 21st Century, Public Law

105–178, and on a proposal from the

Western Governors’ Association (WGA)

for addressing the recommendations of

the Grand Canyon Visibility Transport

Commission (GCVTC) in the final rule.

The EPA received more than 1300

comments overall on the proposal and

notice of availability.

Today’s final rule calls for States to

establish goals and emission reduction

strategies for improving visibility in all

156 mandatory Class I national parks

and wilderness areas. Specific

provisions are included in the rule

allowing nine western States to

implement the recommendations of the

GCVTC within the framework of the

national regional haze program. In

addition, EPA encourages States to work

together in regional partnerships to

develop and implement multistate

strategies to reduce emissions of

visibility-impairing fine particle

pollution.

DATES: The regulatory amendments

announced herein take effect on August

30, 1999.

ADDRESSES: Docket. The public docket

for this action is available for public

inspection and copying between 8:00

a.m. and 5:30 p.m., Monday through

Friday excluding legal holidays, at the

Air and Radiation Docket and

Information Center (6102), Attention:

Docket A–95–38, Room M–1500, 401 M

Street, SW, Washington, DC 20460,

phone 202–260–7548, fax 202–260–

4400, email: A-and-RDocket@epamail.epa.gov. A reasonable

fee for copying may be charged. The

regional haze regulations are subject to

the rulemaking procedures under

section 307(d) of the CAA. The

documents relied on to develop the

regional haze regulations have been

placed in the docket.

FOR FURTHER INFORMATION CONTACT: For

general questions regarding this notice,

contact Richard Damberg, U.S. EPA,

MD–15, Research Triangle Park, NC

27711, telephone (919) 541–5592, email:

damberg.rich@epa.gov.

SUPPLEMENTARY INFORMATION:

Electronic Availability

The official record for this

rulemaking, as well as the public

version, has been established under

docket number A–95–38 (including

comments and data submitted

electronically as described below). A

public version of this record, including

printed, paper versions of electronic

comments, which does not include any

information claimed as Confidential

Business Information, is available for

inspection from 8:00 a.m. to 5:30 p.m.,

Monday through Friday, excluding legal

holidays. The official rulemaking record

is located at the address in ADDRESSES

at the beginning of this document.

World Wide Web sites have been

developed for overview information on

visibility issues and related programs.

These web sites can be accessed from

Uniform Resource Locator (URL):

http://www.epa.gov/airlinks/.

Table of Contents

I. Overview of Today’s Final Rule

II. Background Information on the Regional

Haze Program

A. Regional Haze

B. How Today’s Final Rule Responds to the

CAA

C. The 1980 Visibility Regulation—

Commitment to a Regional Haze Program

D. Sources of Scientific Information and

Policy Recommendations on Regional

Haze

E. Relationship to Secondary NAAQS for

PM

F. Regional Planning and Integration with

Programs to Implement the NAAQS for

Ozone and Particulate Matter

III. Discussion of National Program

Requirements and Response to

Comments

A. Scope of Rule—Extending Coverage to

All States

B. Timetable for Submitting the First

Regional Haze SIP

C. Tracking Deciviews and Emissions

Reductions

D. Regional Haze Implementation Plan

Principles

E. Determination of ‘‘Baseline,’’ ‘‘Natural’’

and ‘‘Current’’ Visibility

F. Reasonable Progress Goals

G. Long-Term Strategy

H. Best Available Retrofit

Technology(BART)

I. Monitoring Strategy and Other

Implementation Plan Requirements

J. Periodic SIP Revisions and 5-Year

Progress Reports

K. Coordination with Federal Land

Managers

IV. Treatment of the GCVTC

Recommendations

A. Background

B. General Requirements of Section 51.309

C. Elements of the GCVTC-Based State and

Tribal Implementation Plans

D. Requirements for States Electing Not To

Follow All Provisions of the Section

51.309(e)

E. Annex to the GCVTC Report

F. Additional Class I Areas

V. Implementation of the Regional Haze

Program in Indian Country

A. Background on Tribal Air Quality

Programs

B. Issues Related to the Regional Haze

Program in Indian Country

VI. Miscellaneous Technical Amendments to

the Existing Rule

VII. Administrative Requirements

A. Regulatory Planning and Review by the

Office of Management and Budget (OMB)

(Executive Order 12866)

B. Regulatory Flexibility Act

C. Paperwork Reduction Act—Impact on

Reporting Requirements

D. Unfunded Mandates Reform Act

E. Environmental Justice—Executive Order

12898

F. Congressional Review Act

G. Protection of Children From

Environmental Health Risks and Safety

Risks—Executive Order 13045

H. Enhancing the Intergovernmental

Partnership— Executive Order 12875
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35715

1U.S. EPA. Air Quality Criteria for Particulate

Matter. Office of Research and Development,

National Center for Environmental Assessment.

EPA/600/P–95/001bF. Research Triangle Park, NC.

1996.

2H.R. Rep. No. 95–294 at 204 (1977).

3National Park Service. Air Quality in the

National Parks: A Summary of Findings from the

National Park Service Air Quality Research and

Monitoring Program. Natural Resources Report 88–

1. Denver, CO, July 1988.

4Areas designated as mandatory Class I Federal

areas are those national parks exceeding 6000 acres,

wilderness areas and national memorial parks

exceeding 5000 areas, and all international parks

which were in existence on August 7, 1977.

Visibility has been identified as an important value

in 156 of these areas. See 40 CFR part 81, subpart

D. The extent of a Class I area includes subsequent

changes in boundaries, such as park expansions.

(CAA section 162(a)). States and tribes may

designate additional areas as Class I, but the

requirements of the visibility program under section

169A of the CAA apply only to ‘‘mandatory Class

I Federal areas,’’ and they do not directly address

any additional areas.

5 ‘‘Deciview’’ is a visibility metric discussed

further in unit III.C. of today’s notice, and defined

in section 51.301(bb) of the rule. Higher deciview

values indicate greater levels of visibility

impairment.

6See National Acid Precipitation Assessment

Program. Acid Deposition: State of Science and

Technology. Report 24, Visibility: Existing and

Historical Conditions—Causes and Effects, Table

24–6. Washington, DC 1991. See also U.S. EPA. Air

Quality Criteria for Particulate Matter. Office of

Research and Development, National Center for

Environmental Assessment. EPA/600/P–95/001bF.

Research Triangle Park, NC. 1996.

7For the purposes of this preamble, the term

‘‘Class I area’’ will be used to describe the 156

mandatory Class I Federal areas identified in

section 51.301(o) and in part 81, subpart D of this

title.

8H.R. Rep. No. 294, 95th Cong. 1st Sess. at 205

(1977).

9 ‘‘Reasonably attributable’’ visibility impairment,

as defined in section 51.301(s), means ‘‘attributable

by visual observation or any other technique the

State deems appropriate.’’ It includes impacts to

Class I areas caused by plumes or layered hazes

from a single source or small group of sources.

10H.R. Rep. No. 95–294 at 204 (1977).

11 45 FR 80084 (December 2, 1980) and section

51.300–307.

I. Executive Order 13084: Consultation and

Coordination with Indian Tribal

Governments

J. National Technology Transfer and

Advancement Act

I. Overview of Today’s Final Rule

This preamble provides the details

and rationale for the final regional haze

rule. Unit II includes background

information on regional haze and on the

legal and scientific basis for today’s

action. Unit III describes the provisions

of the national requirements for regional

haze and includes a discussion of the

comments received on the July 1997

proposal. Unit IV discusses specific

regional provisions for 16 western Class

I areas that were the subject of a 1996

report by the GCVTC. Unit V is a

discussion of issues related to

implementation of the rule by Indian

tribes. Unit VI summarizes several

technical amendments to existing

visibility regulations in order to

coordinate those requirements with the

requirements of today’s final rule. Unit

VII discusses how today’s final

rulemaking is in compliance with the

requirements of various executive

orders and statutes.

II. Background Information on the

Regional Haze Program

A. Regional Haze

Regional haze is visibility impairment

that is produced by a multitude of

sources and activities which emit fine

particles and their precursors and which

are located across a broad geographic

area.1 Twenty years ago, when initially

adopting the visibility protection

provisions of the CAA, Congress

specifically recognized that the

‘‘visibility problem is caused primarily

by emission into the atmosphere of SO2,

oxides of nitrogen, and particulate

matter, especially fine particulate

matter, from inadequate[ly] controlled

sources.’’ 2 The fine particulate matter

(PM) (e.g., sulfates, nitrates, organic

carbon, elemental carbon, and soil dust)

that impairs visibility by scattering and

absorbing light can cause serious health

effects and mortality in humans, and

contribute to environmental effects such

as acid deposition and eutrophication.

Data from the existing visibility

monitoring network show that visibility

impairment caused by air pollution

occurs virtually all the time at most

national park and wilderness area

monitoring stations.3 Average visual

range in many Class I areas 4 in the

Western United States is 100–150

kilometers (13.6–9.6 deciviews), 5 or

about one-half to two-thirds of the

visual range that would exist without

manmade air pollution. In most of the

east, the average visual range is less

than 30 kilometers (25 deciviews or

more), or about one-fifth of the visual

range that would exist under estimated

natural conditions. The role of regional

transport of fine particles in

contributing to elevated PM levels and

regional haze impairment has been well

documented by many researchers 6 and

recognized as a significant issue by

policymakers from Federal, State and

local agencies, industry and

environmental organizations.

B. How Today’s Final Rule Responds to

the CAA

The visibility protection program

under sections 169A, 169B, and

110(a)(2)(J) of the CAA is designed to

protect Class I areas 7 from impairment

due to manmade air pollution. Congress

adopted the visibility provisions in the

CAA to protect visibility in these ‘‘areas

of great scenic importance.’’ 8 The

current regulatory program addresses

visibility impairment in these areas that

is ‘‘reasonably attributable’’ 9 to a

specific source or small group of

sources. In adopting section 169A, the

core visibility provisions adopted in the

1977 CAA Amendments, Congress also

expressed its concern with visibility

problems caused by pollutants that

‘‘emanate from a variety of sources.’’ It

noted the problem of ‘‘hazes’’ from

‘‘regionally distributed sources,’’ 10 and

concluded that additional provisions

were needed to remedy ‘‘the growing

visibility problem.’’ The purpose of

today’s final rule is to revise the existing

visibility regulations 11 in order to

integrate provisions addressing regional

haze impairment. Today’s final rule

establishes a comprehensive visibility

protection program for Class I areas.

Figure 1 is a map indicating the

locations of the Class I areas.

BILLING CODE 6560–50–U
35716 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

BILLING CODE 6560–50–C
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35717

12The States and one territory having at least one

Class I area are listed in section 51.300(b)(2). These

States and one territory are as follows: Alabama,

Alaska, Arizona, Arkansas, California, Colorado,

Florida, Georgia, Hawaii, Idaho, Kentucky,

Louisiana, Maine, Michigan, Minnesota, Missouri,

Montana, Nevada, New Hampshire, New Jersey,

New Mexico, North Carolina, North Dakota,

Oklahoma, Oregon, South Carolina, South Dakota,

Tennessee, Texas, Utah, Vermont, Virginia, Virgin

Islands, Washington, West Virginia, and Wyoming.

For a specific list of Class I areas located in each

state or territory, see 40 CFR 81.401–437.

13 45 FR 80086.

14National Research Council Committee on Haze

in National Parks and Wilderness Areas, Protecting

Visibility in National Parks and Wilderness Areas,

National Academy Press, 1993, p. 11.

15State of Maine v. Thomas, 874 F.2d 883, 885

(1st Cir. 1989) (‘‘EPA’s mandate to control the

vexing problem of regional haze emanates directly

from the CAA, which ‘declares as a national goal

the prevention of any future, and the remedying of

any existing, impairment of visibility in Class I

areas which impairment results from manmade air

pollution.’ ’’) (citation omitted).

16U.S. EPA, Interim Findings on the Status of

Visibility Research, Office of Research and

Development, EPA/600/R–95/021, February 1995.

See also 60 FR 8659 notice announcing the report

availability and how to obtain copies (Feb. 15, 1995.

17U.S. EPA, Effects of the 1990 CAA

Amendments on Visibility in Class I Areas: An EPA

Report to Congress, October 1993 (EPA–452/R–93–

014).

18CAA section 169B(d)(2)(C).

19 56 FR 57522, November 12, 1991.

20 Grand Canyon Visibility Transport

Commission, Recommendations for Improving

Western Vistas, Report to the U.S. EPA, June 10,

1996 (hereafter referred to as ‘‘GCVTC Report’’).

21CAA section 169B(e)(1).

C. The 1980 Visibility Regulation—

Commitment to a Regional Haze

Program

Section 169A of the CAA, established

in the 1977 Amendments, sets forth a

national visibility goal that calls for ‘‘the

prevention of any future, and the

remedying of any existing, impairment

of visibility in Class I areas which

impairment results from manmade air

pollution.’’ The EPA’s initial visibility

regulations, developed in 1980, address

visibility impairment that is ‘‘reasonably

attributable’’ to a single source or small

group of sources. Under the 1980 rules,

the 35 States and 1 territory containing

Class I areas 12 are required to:

(1) Revise their SIPs to assure

reasonable progress toward the national

visibility goal;

(2) Determine which existing

stationary facilities should install the

best available retrofit technology

(BART) for controlling pollutants which

impair visibility;

(3) Develop, adopt, implement, and

evaluate long-term strategies for making

reasonable progress toward remedying

any existing and preventing any future

impairment in the Class I areas;

(4) Adopt certain measures to assess

potential visibility impacts due to new

or modified major stationary sources,

including measures to notify Federal

land managers (FLMs) of proposed new

source permit applications, and to

consider visibility analyses conducted

by FLMs in their new source permitting

decisions; and

(5) Conduct visibility monitoring in

Class I areas.

The 1980 rules addressing

‘‘reasonably attributable’’ visibility

impairment were designed to be the first

phase in EPA’s overall program to

protect visibility. The EPA explicitly

deferred national rules addressing

regional haze impairment until some

future date:

* * * when improvement in monitoring

techniques provides more data on sourcespecific levels of visibility impairment,

regional scale models become refined, and

our scientific knowledge about the

relationships between emitted air pollutants

and visibility impairment improves.13

The EPA believes that the technical

tools and our scientific understanding of

visibility impairment are now

sufficiently refined to move forward

with a national program addressing

regional haze in Class I areas. The EPA’s

position is supported by the NAS 1993

report, Protecting Visibility in National

Parks and Wilderness Areas. One of the

principal conclusions of this report is

that ‘‘current scientific knowledge is

adequate and control technologies are

available for taking regulatory action to

improve and protect visibility.’’ 14

Section II.D. describes a number of other

studies and information now available

which provide the technical basis to

move forward with a regional haze

program.

In addition, EPA finds the visibility

protection provisions of the CAA to be

quite broad. Although EPA is addressing

visibility protection in phases, the

national visibility goal in section 169A

calls for addressing visibility

impairment generally, including

regional haze.15

Further, Congress added section 169B

as part of the 1990 Amendments to the

CAA to focus attention on regional haze

issues; it calls for EPA to issue regional

haze rules within 18 months of receipt

of the final report from the GCVTC. In

addition, section 169B includes

provisions for EPA to conduct visibility

research with the National Park Service

and other Federal agencies, to develop

an interim findings report on the

visibility research,16 to develop a Report

to Congress on expected visibility

improvements due to implementation of

other air pollution programs,17 and to

provide periodic reports to Congress on

trends in visibility improvements.

Section 169B also provides the authority

to the Administrator to establish

visibility transport commissions in

response to a petition from two or more

States, or on her and/or his own motion.

To date, EPA has not received any

petitions from groups of States

requesting formation of a visibility

transport commission.

Section 169B(f) called for EPA to

establish a visibility transport

commission for the region affecting

visibility of the Grand Canyon National

Park. The purpose of this commission

was to assess scientific and technical

information pertaining to adverse

impacts on visibility at the Park from

existing emissions and projected growth

in emissions. The statute specifically

called for a report to EPA

recommending measures to remedy

such impacts and to address long-term

strategies for addressing regional haze.18

In 1991, EPA established the GCVTC,19

and the GCVTC issued its final report in

June 1996.20 The recommendations of

the GCVTC and their incorporation as

potential SIP requirements into the final

rule, are discussed in greater detail in

unit IV of the preamble.

Finally, section 169B(e) calls for the

Administrator to consider past research

and the recommendations of visibility

transport commissions in carrying out

the ‘‘regulatory responsibilities under

section 169A, including criteria for

measuring ‘reasonable progress’ toward

the national goal.’’ 21 The EPA is

required by the CAA to meet these

regulatory responsibilities within 18

months of receiving the GCVTC report.

Today’s final rule fulfills EPA’s

responsibility under section 169A,

pending since 1980, to put in place a

national regulatory program that

addresses both reasonably attributable

and regional haze visibility impairment.

Today’s action is also EPA’s response to

the GCVTC report as anticipated by

section 169B.

D. Sources of Scientific Information and

Policy Recommendations on Regional

Haze

In developing today’s revisions to the

visibility regulations, EPA has taken

into account a significant body of

scientific information and policy

recommendations on visibility issues

that have been developed over more

than 20 years. This unit highlights key

sources of information upon which the

final regional haze rule is based.

For many years, visibility impairment

has been considered the ‘‘best

understood and most easily measured
35718 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

22Council on Environmental Quality, Visibility

Protection for Class I Areas: The Technical Basis,

Washington, DC, 1978.

23National Research Council, NAS Committee on

Haze in National Parks and Wilderness Areas,

Protecting Visibility in National Parks and

Wilderness Areas, National Academy Press, 1993,

p. 23.

24National Acid Precipitation Assessment

Program (NAPAP), Acid Deposition: State of

Science and Technology. Report 24, Visibility:

Existing and Historical Conditions—Causes and

Effects, Washington, DC, 1991.

25U.S. EPA, Protecting Visibility: An EPA Report

to Congress; Office of Air Quality Planning and

Standards, EPA–450/5–79–008, October 1979.

26Sisler, J. et al., Spatial and Seasonal Patters and

Long-Term Variability of the Chemical Composition

of the Haze in the U.S.: An Analysis of Data from

the IMPROVE Network, Fort Collins, CO,

Cooperative Institute for Research in the

Atmosphere, Colorado State University, 1996. See

also Sisler, J., et al., Spatial and Temporal Patters

and the Chemical Composition of the Haze in the

United States: An Analysis of Data From the

IMPROVE Network, 1988–1991, Fort Callins, CO,

1993.

27U.S. EPA, National Air Quality and Emissions

Trends Report, 1996, Office of Air Quality Planning

and Standards, EPA 454/R–97–013, January 1998.

See also U.S. EPA, National Air Quality and

Emissions Trends Report, 1997, Office of Air

Quality Planning and Standards, EPA 454/R–98–

016, January 1999.

28Atmospheric Environment, Proceedings of EPA

Symposium on Plumes and Visibility—

Measurements and Model Components, November

1980, Atmos. Environ., 15:1785–2646. See also

Bhardwaja, P.J., ed., Visibility Protection: Research

and Policy Aspects. Transactions of APCA

Specialty Conference, September 1986, Grand

Tetons National Park, WY. Air Pollution Control

Assoc., Pittsburgh, PA, 1987. See also Mathai, C.V.,

ed., Visibility and Fine Particles. Transactions of

AWMA specialty conference, October 1989, Estes

Park, CO. Air and Waste Management Assoc.,

Pittsburgh, PA, 1990.

29National Acid Precipitation Assessment

Program (NAPAP), Acid Deposition: State of

Science and Technology, Report 24, Visibility:

Existing and Historical Conditions—Causes and

Effects, Washington, DC, 1991.

30National Research Council, NAS Committee on

Haze in National Parks and Wilderness Areas,

Protecting Visibility in National Parks and

Wilderness Areas, National Academy Press,

Washington, DC, 1993.

31U.S. EPA, Effects of the 1990 Clean Air Act

Amendments on Visibility in Class I Areas: An EPA

Report to Congress, Office of Air Quality Planning

and Standards, EPA–452/R–93–014, October 1993.

effect of air pollution.’’ 22 Visibility

degradation has also been recognized as

an indicator of multiple human-health

effects and environmental effects

resulting from air pollution all over the

world.23 Visibility conditions have been

monitored and evaluated for many

years, using airport visibility data

collected from the 1940’s to the

present.24

In October 1979, EPA published a

Report to Congress describing the state

of the science on visibility.25 The report,

required under section 169A(a)(3),

described available methods for

visibility monitoring, modeling, and

assessment of strategies to make

progress toward the national goal. This

report was developed in advance of the

1980 visibility regulations. As noted

above, EPA deferred action on regional

haze until monitoring techniques,

modeling capabilities, and the

understanding of the pollutants

affecting visibility were improved. In

1986, the IMPROVE (Interagency

Monitoring of Protected Visual

Environments) visibility monitoring

program was initiated in 30 Class I

areas. The IMPROVE program has been

coordinated through a cooperative,

multiagency approach with

participation by EPA, the FLMs, and

States. Through the IMPROVE program,

significant progress has been made in

understanding the effect of various

pollutants on current visibility

conditions and trends, in developing

well-accepted monitoring protocols, and

in developing a sound approach for

calculating light extinction values from

aerosol and humidity data. The

IMPROVE program has issued two

major reviews of the monitoring data

collected to date,26 and numerous

technical papers have been developed

using data collected by the network.

In addition, in 1996 EPA began to

include a chapter on visibility trends,

based on data collected throughout the

IMPROVE network, in the National Air

Quality and Emissions Trends Report in

1996.27 Data from 1988 to the present

are analyzed for the best 20 percent,

middle 20 percent, and worst 20 percent

days of the annual distribution, and

aggregated for eastern and western sites.

Annual summary data are also

presented for each individual site in an

appendix.

Visibility research continued

throughout the 1980’s and is

documented in many published articles

and the proceedings of three major

visibility conferences.28 In addition, the

NAPAP completed a comprehensive

review of the state of the science of

visibility in 1991.29 This peer-reviewed

report reached a number of important

conclusions, including: (1) Light

scattering is dominated by fine particles;

(2) sulfates are the dominant source of

light extinction in the east, and one of

several major sources of extinction in

the west; (3) rural visibility varies

significantly between the east and west;

(4) average natural visibility conditions

are 150 kilometers visual range (9.6

deciviews) in the east and 230

kilometers visual range (5.3 deciviews)

in the west; and (5) haze trends in the

eastern United States have been

dominated by sulfur emission trends

since the late 1940’s.

The NAS formed a Committee on

Haze in National Parks and Wilderness

Areas in 1990 to address a number of

regional haze-related issues, including

methods for determining anthropogenic

source contributions to haze and

methods for considering alternative

source control measures. The 1993

report by this Committee contributed

significantly to the state of the science

regarding regional haze visibility

impairment.30 The Committee issued

several important conclusions in the

report, including: (1) Current scientific

knowledge is adequate and control

technologies are available for taking

regulatory action to address regional

haze; (2) progress toward the national

goal will require regional programs that

operate over large geographic areas and

limit emissions of pollutants that can

cause regional haze; (3) a program to

address regional haze visibility

impairment that focuses solely on

determining the contributions of

individual emission sources to such

visibility impairment is likely to fail,

and instead, strategies should be

adopted to consider simultaneously the

effect of many sources on a regional

basis; (4) visibility impairment can be

attributed to emission sources on a

regional scale through the use of several

kinds of models; (5) visibility and

control policies might need to be

different in the west than the east; (6)

efforts to improve visibility within Class

I areas will benefit visibility outside

these areas and could help alleviate

other types of air quality problems as

well; (7) achieving the national visibility

goal will require a substantial, long-term

program; and (8) continued progress

toward this goal will require a greater

commitment toward atmospheric

research, monitoring, and emissions

control research and development.

Also in 1993, EPA developed its

Report to Congress on the projected

effects on visibility in Class I areas due

to implementation of the 1990 CAA

Amendments. 31 The report concluded

that conditions on the worst visibility

days are expected to improve by

approximately 3 deciviews by 2010

across the most impaired portions of the

Eastern United States. Most of this

improvement is expected in the 1995–

2005 timeframe due to sulfur dioxide

reductions under the acid rain program.

In the Southwestern United States, the

visibility change was predicted to be

less than 1 deciview in most Class I

areas except San Gorgonio Wilderness

(which is located downwind of Los

Angeles), for which a 1–2 deciview

improvement is expected.
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35719

32U.S. EPA, Interim Findings on the Status of

Visibility Research, Office of Research and

Development, EPA/600/R–95/021, February 1995.

33These repdorts have already been mentioned in

this section: the 1993 NAS report, the 1993

IMPROVE report (Sisler et al.), the 1993 EPA Report

to Congress, and the 1991 NAPAP Report to

Congress.

34 56 FR 57523

35CAA Section 169B(d).

36A clean air corridor is defined as a region that

generally brings clear air to a receptor region, such

as the Class I areas of the Golden Circle.

37National Research Council, NAS Committee on

Haze in National Parks and Wilderness Areas,

Protecting Visibility in National Parks and

Wilderness Areas, National Academy Press,

Washington, DC, 1993, p. 11.

38 62 FR 38652 (July 18, 1997).

39See section 160(1); H.R. Rep. No. 95–294 at 205

(1977).

As required by section 169B(a)(2) of

the CAA, EPA issued a report in 1995

on interim findings on the status of

visibility research completed since

1990.32 This report reviewed four major

visibility related reports published since

1990,33 provided citations of published

research papers, and summarized

research under way by the GCVTC, four

Federal agencies, and the Electric Power

Research Institute. As noted above, the

GCVTC issued a report in June 1996

containing recommendations for

protecting visibility at 16 Class I areas

on the Colorado Plateau. Based on

EPA’s discretionary authority under

section 169B(c), it expanded the scope

of the GCVTC:

* * * to include additional Class I areas in

the vicinity of the Grand Canyon National

Park—-what is sometimes referred to as the

‘‘Golden Circle’’ of parks and wilderness

areas. This includes most of the national

parks and national wilderness areas of the

Colorado Plateau.34

The GCVTC was charged with

assessing information about visibility

impacts in the region and making policy

recommendations to EPA to address

such impacts. The CAA called for the

GCVTC to assess studies conducted

under section 169B as well as other

available information ‘‘pertaining to

adverse impacts on visibility from

potential or projected growth in

emissions for sources located in the

* * * Region,’’ and to issue a report to

EPA recommending what measures, if

any, should be taken to protect

visibility. 35 The CAA specifically

provided for the GCVTC’s report to

address the following measures: (1) The

establishment of clean air corridors, in

which additional restrictions on

increases in emissions may be

appropriate to protect visibility in

affected Class I areas; (2) the imposition

of additional new source review

requirements in clean air corridors; 36

and (3) the promulgation of regulations

addressing regional haze.

In unit IV of the proposal, EPA

discusses the major recommendations of

the GCVTC. The GCVTC’s

recommendations have components that

contemplate implementation through a

combination of actions by EPA, other

Federal agencies, States and tribes in the

region, and voluntary measures on the

part of public and private entities

throughout the region. The GCVTC’s

recommendations also distinguish

between recommended actions and

policy or strategy options for

consideration. Unit IV addresses how

EPA took these recommendations, as

well as the body of technical

information developed by the GCVTC,

into account in developing the final

rule.

Response to comments. Some

commenters on the regional haze

proposal suggested that EPA had not

provided an adequate scientific or legal

justification for developing a regional

haze program. The commenters asserted

that the science of regional haze is not

understood well enough to develop

regulations at this time. In addition,

some commenters claimed that EPA has

not provided adequate technical

guidance for implementation of the rule,

and that providing such guidance is a

legal prerequisite to promulgating a

regional haze rule. The EPA does not

agree with these claims.

First, EPA believes it has relied upon

a substantial amount of scientific

evidence to support development of the

regional haze program. Many of the

important studies, reports, and other

scientific and technical information on

which the regional haze rule is based

are referenced earlier in this section. In

particular, the NAS Committee on Haze

in National Parks and Wilderness Areas

concluded that ‘‘Current scientific

knowledge is adequate and control

technologies are available for taking

regulatory action to improve and protect

visibility.’’ 37 Thus, EPA believes that its

decision to move forward with

promulgation of the regional haze

program is reasonable, particularly in

light of the fact that the Agency’s

obligation to address regional haze

originated more than 20 years ago with

passage of the 1977 CAA Amendments.

Second, as discussed in the response

to comments, today’s final rule provides

the States with the necessary guidelines

to implement a regional haze program.

The EPA believes that the supposition

that all technical guidance associated

with a program be developed before a

rule can be promulgated is unfounded.

The EPA recognizes the importance of

timely implementation guidance and is

committed to providing such guidance,

as appropriate, for the regional haze

program.

The EPA does not interpret sections

169A and 169B as requiring all

technical guidance to be issued by the

Agency before the rule is finalized. The

EPA is committed to working closely

with the States and other interested

parties in developing effective guidance

documents within a reasonable period

of time after promulgation of the final

regional haze rule.

E. Relationship to Secondary NAAQS

for PM

Today’s final rule is an important

element in EPA’s overall approach to

protecting visibility under the CAA. In

July 1997, EPA established national

secondary ambient air quality standards

(NAAQS) for particles with an

aerodynamic diameter less than or equal

to a nominal 2.5 micrometers (PM2.5) as

part of its final decision on revision of

the existing NAAQS for particulate

matter under section 109(d) of the

CAA.38 The secondary standards were

based on EPA’s determination that the

levels selected were ‘‘requisite to protect

the public welfare’’ against visibility

impairment on a nationally uniform

basis as provided in section 109(b).

Consistent with the purposes of section

169A, however, EPA recognized that

such nationally uniform standards

would not eliminate all visibility

impairment in all parts of the country.39

The visibility impacts remaining in

Class I areas are addressed by today’s

final rule.

Today’s final rule has additional

benefits, as EPA expects the regional

strategies implemented as part of the

regional haze program to improve

visibility outside of Class I areas as well.

Thus, the regional haze program should

contribute to the improvement of local

visibility impacts outside of Class I

areas that may persist after attainment of

the secondary standards.

F. Regional Planning and Integration

With Programs to Implement the

NAAQS for Ozone and Particulate

Matter

The regional haze program is being

promulgated in a manner that facilitates

integration of emission management

strategies for regional haze with the

implementation of programs for new

NAAQS for ozone and PM. This is being

done because of the existing scientific

evidence that these air quality problems

have common precursor pollutants,

emission sources, atmospheric

processes, spatial scales for transport,

and geographic areas of concern.
35720 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

40Subcommittee for Ozone, Particulate Matter,

and Regional Haze Implementation Programs, Final

Report on Subcommittee Discussions, May 1998.

41See the November 17, 1998 draft of

Implementation Guidance for the Ozone and

Particulate Matter NAAQS and Regional Haze

Program. EPA’s internet site for an electronic

version of this guidance: http://www.epa.gov/ttn/

oarpg/tlpgm.html.

Because of the key role of regional

pollutant transport in contributing to

haze at Class I areas, most of which are

in remote locations, the regional haze

program recognizes the value of

multistate coordination for regional

haze program planning and

implementation. Consistent with the

recommendations of the Clean Air Act

Advisory Committee, Subcommittee on

Ozone, Particulate Matter, and Regional

Haze Implementation Programs,40 EPA

strongly encourages States to undertake

multistate regional planning efforts

addressing regional haze in a way that

coordinates technical analyses and

strategy development with the NAAQS

to the maximum extent possible.

Examples of ongoing coordination

among States to address visibility issues

include the Western Regional Air

Partnership (WRAP) and the Southern

Appalachian Mountain Initiative.

The EPA believes that States (and

tribes, at their discretion), in

partnership with other interested

stakeholders, should consider

conducting future regional air quality

planning efforts to address the

implementation of the ozone and PM

NAAQS and regional haze program. We

encourage States to continue to work

together to establish common protocols

and approaches for emissions inventory

development, emissions tracking,

application of regional models, and

development of effective emission

reduction strategies.

The EPA plans to participate early

and actively in regional planning efforts.

The EPA recognizes that we must

provide early input on issues and to

make our views known as issues arise.

The EPA has a responsibility to

independently review the adequacy of

implementation plans in the public

rulemaking process and to consider all

public comments received on a plan in

determining if it meets applicable

requirements. However, it is equally

important that EPA be open in letting

participants know of our views and

concerns throughout the process.

The EPA will soon issue final

guidance on such regional planning

efforts for the purposes of implementing

the ozone, particulate matter, and

regional haze implementation

programs.41 Also, as a part of EPA’s

1999 fiscal year budget, Congress

provided $4 million dollars to support

regional planning activities. EPA is

currently involved with the States in a

process to define the appropriate size

and composition of regional planning

bodies. The final planning guidance will

provide a discussion of several

important issues related to regional

planning efforts. These issues include:

• Taking credit for emissions

reductions in other States;

• Important principles for future

regional planning efforts;

• The technical assessment process;

and

• The strategy development process.

Some important principles discussed in

the guidance for conducting regional

planning efforts include the following

points.

• Regional planning efforts should be

a product of State (and, at the discretion

of any tribe, tribal) leadership and, thus,

should be led by States (and tribes), not

EPA. Representatives should have the

authority to speak for their

organizations.

• States (and tribes at their discretion)

should be prepared to make strong,

early commitments to implementing the

outcome of the regional process to

ensure that SIP submittal dates are met.

• Participants in regional planning

efforts should set up a work plan to

carry out their work. The work plan

should contain clearly stated products

of the process, dates for completion of

those products and mechanisms for

funding the needed analyses.

• The technical assessment process

should include steps for problem

definition, development of emissions

inventories, and development of tools to

evaluate strategy alternatives.

• In the strategy development

process, participants should strive to

develop a consensus about (1) the set of

regional emissions reductions strategies

needed to attain the NAAQS or make

‘‘reasonable progress’’ toward the

national visibility goal in Class I areas,

and (2) the degree to which each State

and relevant source category should be

required to reduce emissions to

implement the recommended strategies.

III. Discussion of National Program

Requirements and Response to

Comments

• Scope of Rule—Extending Coverage

to All States

Proposed rule. In the regional haze

proposal, EPA proposed to amend

section 51.300(b)(3) to extend coverage

to all States (excluding certain

territories) for the purpose of addressing

regional haze visibility impairment.

This approach differed from the 1980

visibility regulations for ‘‘reasonably

attributable’’ impairment, which

required the 35 States and the Virgin

Islands containing Class I areas to

submit SIP revisions and to revise them

periodically to assure reasonable

progress toward the national visibility

goal. Thus, under the proposal, the

following additional States and the

District of Columbia would be required

to submit visibility SIPs: Nebraska,

Kansas, Iowa, Wisconsin, Illinois,

Indiana, Ohio, Mississippi, New York,

Pennsylvania, Massachusetts, Rhode

Island, Connecticut, and Maryland. The

territories of Puerto Rico, Guam,

American Samoa, and the Northern

Mariana Islands were not included

because their distance from any Class I

area significantly exceed the distance

that their emissions could be expected

to be transported in order to contribute

to visibility impairment in any Class I

area. However, Hawaii, Alaska, and the

Virgin Islands would be subject to the

regional haze provisions because of the

potential for emissions from sources

within their borders to contribute to

regional haze impairment in Class I

areas also located within their own

jurisdiction.

In the proposal, EPA also

recommended that all States initially

participate in regional planning efforts

to more precisely characterize which

States are contributing to visibility

impairment in other States, as well as

the magnitude of such contributions.

States could then develop strategies for

making reasonable progress in Class I

areas throughout the region. The EPA

noted that as a result of this process, all

States may not have to adopt control

strategies. At the same time, EPA cited

the 1993 NAS report, which observed

that the requirement for a State to revise

its implementation plan if it ‘‘may

reasonably be anticipated’’ to contribute

to visibility impairment indicates that

Congress intended that ‘‘the philosophy

of precautionary action should apply to

visibility protection as it applies to

other areas [such as the NAAQS].’’

Thus, EPA proposed that, at a

minimum, all States should be required

to develop visibility SIPs in order to

‘‘prevent any future impairment’’ as

called for by the national goal in section

169A(a)(1).

Contracts received. The EPA received

a number of comments on the proposed

applicability provisions. Many

commenters approved of EPA’s

approach to require SIPs from all States.

Those who did not agree with the scope

of the program provided a number of

reasons for their opposition. Some

commenters recognized the need for a

regional haze program, but stated that

EPA must first conduct or review
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35721

42Central Arizona Water Conservation District v.

EPA, 990 F.2d 1531 (1993). 43 990 F.2d at 1541.

44Refer to unit II of this final rule for additional

background on the long-range transport of pollution

contributing to regional haze.

45See Unit II, Background Information. See also

July 29, 1997 memorandum to regional haze docket

A–95–38, ‘‘Supporting Information for Proposed

Applicability of Regional Haze Regulations,’’ by

Richard Damberg, EPA, Office of Air Quality

Planning and Standards.

46U.S. EPA, Protecting Visibility: An EPA Report

to Congress, Office of Air Quality Planning and

Standards, EPA–450/5–79–008, October 1979.

additional scientific analyses in order to

provide justification for requiring

additional States to submit visibility

SIPs. Other commenters felt that in the

proposed applicability provisions, EPA

exceeded its statutory authority by

extending the regional haze program to

States that have not been demonstrated

to ‘‘cause or contribute’’ to visibility

impairment. Some commenters

suggested that EPA rely on States with

Class I areas to engage nearby States, as

appropriate, in regional planning efforts.

Some commenters in States containing

Class I areas suggested that, for their

particular Class I areas, there was no

demonstrated visibility problem. They

asserted that because visibility levels

should already be deemed acceptable,

there was no need for a regional haze

program in their States. Other

commenters felt that EPA should

include specific criteria (e.g., distance,

emissions, and visibility impact cutoffs)

for excluding States or geographic areas

from consideration as contributing to

regional haze visibility impairment.

Final rule. Consistent with the

proposal, EPA has concluded in today’s

final rule that all States contain sources

whose emissions are reasonably

anticipated to contribute to regional

haze in a Class I area and, therefore,

must submit regional haze SIPs. The

rationale for this finding is discussed in

more detail below.

In making this finding, EPA

considered three factors: (1) The specific

statutory language in the CAA; (2) the

weight of evidence demonstrating longrange transport of fine particulate

pollution that affects visibility in Class

I areas; and (3) current monitored

conditions in Class I areas across the

country. The EPA’s consideration of

each of these factors is discussed below.

Two key provisions in section 169A

support EPA’s finding that all States

must develop SIPs for regional haze.

Section 169A(b)(2) requires EPA to

promulgate regulations to require SIPs

from those States where the emissions

‘‘may reasonably be anticipated to cause

or contribute to any impairment of

visibility’’ in a mandatory Class I

Federal area. The EPA believes that this

provision does not require the Agency

to provide absolute certainty regarding

the effect of emissions from the State on

visibility in a particular Class I area.

The Ninth Circuit has interpreted the

language, ‘‘may reasonably be

anticipated to cause or contribute to any

impairment of visibility,’’ in a case

involving identical language in section

169A(b)(2)(A) relating to BART.42 The

EPA believes that the court’s

interpretation of this phrase may be

appropriately used in regard to program

applicability as well. In its decision, the

court found that the language ‘‘may

reasonably be anticipated to cause or

contribute’’ establishes an ‘‘extremely

low triggering threshold’’ for requiring a

source to control emissions, adding that

‘‘the NAS correctly noted that Congress

has not required ironclad scientific

certainty establishing the precise

relationship between a source’s

emission and resulting visibility

impairment. * * *’’ 43 In considering

whether additional States should be

subject to the visibility program, EPA

believes the court’s reasoning supports

adoption of the predicate requirement

that States develop the necessary

provisions in their implementation

plans to determine whether and to what

extent control of emissions from sources

is needed. That is, given that the court

believed this ‘‘low triggering threshold’’

was sufficient to require a source to

control its emissions under BART, EPA

believes it is reasonable that a similarly

low or even lower threshold applies to

whether States should be required to

engage in air quality planning and

analysis as a prerequisite to determining

the need for control of emissions from

sources within their State. The EPA

believes this is particularly appropriate

since the requirement for SIPs does not

mandate the actual control of emissions

from any source without further

technical analysis by the State.

Accordingly, EPA believes the concept

of an ‘‘extremely low triggering

threshold’’ can also apply in

determining which States should submit

SIPs for regional haze.

Section 169A(a)(1) sets forth a

national goal of ‘‘the prevention of any

future, and the remedying of any

existing, impairment of visibility in

Class I areas which impairment results

from manmade air pollution.’’ Thus, in

addition to requiring a program to

reduce existing impairment, the CAA

requires SIPs to be established in order

to prevent future impairment. This

preventative component of the national

goal requires that States have the

framework in place to address future

growth in emissions from new sources

or other activities that could impair

visibility. For this reason, the EPA does

not believe that it is appropriate to

establish criteria for excluding States or

geographic areas from consideration as

potential contributors to regional haze

visibility impairment.

As noted in the proposal, EPA is not

specifying in this final rule what

specific control measures a State must

implement in its initial SIP for regional

haze. That determination can only be

made by a State once it has conducted

the necessary technical analyses of

emissions, air quality, and the other

factors that go into determining

reasonable progress. As discussed in

section II(F), because of the regional,

multistate nature of visibility

impairment in Class I areas,44 EPA

recommends that these analyses and the

determination of the extent of emissions

reductions needed from individual

States be developed and refined through

multistate planning efforts using the

best available technical tools, such as

regional-scale modeling. The EPA also

recommends the coordination of

resulting strategies for regional haze

with strategies needed to attain the

PM2.5 NAAQS. The EPA anticipates that

as a result of the more refined analyses

required by this rule, some States may

conclude that control strategies

specifically for protection of visibility

are not needed at this time because the

analyses may show that existing

measures are sufficient to meet

reasonable progress goals. The EPA is

requiring States to document their

analyses, including any consultations

with other States in support of their

conclusions that further controls are not

needed at this time. The EPA believes

that there is more than sufficient

evidence to support our conclusion that

emissions from each of the 48

contiguous States may be reasonably

anticipated to cause or contribute to

visibility impairment in a Class I area.

As stated in EPA’s proposal, a large

body of evidence demonstrates that

long-range transport of fine PM

contributes to regional haze and other

related effects such as acid rain. In the

preamble to the proposal and in the

relevant docket, EPA cited numerous

studies that contribute to this body of

evidence.45 Indeed, EPA recognized the

role of long-range transport in relation

to visibility impairment 20 years ago in

its 1979 Report to Congress on

visibility.46

Among the more important studies on

which EPA relied are the 1991 report

from the NAPAP, the 1993 NAS report

Protecting Visibility in National Parks
35722 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

47See Latimer and Associates, Particulate Matter

Source—Receptor Relationships Between All Point

and Area Sources in the United States and PSD

Class I Area Receptors, Report prepared for EPA,

Office of Air Quality Planning and Standards,

September 1996. See also ENVIRON International

Corporation, Development of Revised Federal Class

I Area Groups in Support of Regional Haze

Regulations, Report prepared for EPA, Office of Air

Quality Planning and Standards, September 1996.

48National Acid Precipitation Assessment

Program. Acid Deposition: State of the Science and

Technology. Report 24, Visibility: Existing and

Historical Conditions—Causes and Effects,

Washington, DC, 1991.

49National Research Council, NAS Committee on

Haze in National Parks and Wilderness Areas,

Protecting Visibility in National Parks and

Wilderness Areas, National Academy Press,

Washington, D.C., 1993.

50 Dennis, Robin L. ‘‘Using the Regional Acid

Deposition Model to Determine the Nitrogen

Deposition Airshed of the Chesapeake Bay

Watershed,’’ in Atmospheric Deposition to the

Great Lakes and Coastal Waters, edited by Joel

Baker, 1996.

51 GCVTC, Recommendations for Improving

Western Vistas, Report to the U.S. EPA, June 1996.

52Sisler, J. et al., Spatial and Seasonal Patterns

and Long-Term Variability of the Chemical

Composition of the Haze in the United States: An

Analysis of Data from the IMPROVE Network, Fort

Collins, CO, Cooperative Institute for Research in

the Atmosphere, Colorado State University, 1996.

See also Sisler, J., et al., Spatial and Temporal

Patterns and the Chemical Composition of the Haze

in the United States: An Analysis of Data from the

IMPROVE Network, 1988–1991, Fort Collins, CO,

1993.

53U.S. EPA, Effects of the 1990 Clean Air Act

Amendments on Visibility in Class I Areas: An EPA

Report to Congress, Office of Air Quality Planning

and Standards, EPA–452/R–93–014, October 1993.

and Wilderness Areas, EPA studies

using the regional acid deposition

model (RADM), the 1996 GCVTC report

Recommendations for Improving

Western Vistas, and two contractor

reports prepared for EPA.47 All of these

reports are available in the docket. They

were referenced and discussed in EPA’s

proposal and in an additional

memorandum to the docket. The

NAPAP report included a

comprehensive technical review of

historical visibility trends.48 The NAS

report found that the range of fine

particle transport is on the order of

hundreds or thousands of kilometers.49

Analyses using the RADM have

estimated that sulfate and nitrate

deposition receptors are influenced by

sources located up to 600–800

kilometers away.50 In its deliberations

and in its final report, the GCVTC

acknowledged the role of long-range

transport from sources and activities

located across a very large geographic

area, and its effect on the Class I areas

on the Colorado Plateau.51

Finally, two contractor modeling

reports prepared for EPA provided

information that preliminarily

demonstrated that each State not having

a Class I area had emissions

contributing to impairment in at least

one downwind Class I area. Some State

commenters asserted that the contractor

reports referenced in the proposal show

relatively low contributions from all or

part of their States toward visibility

impairment in a nearby Class I area. As

a result, these commenters suggested

that EPA had sufficient information to

reach a conclusion that all or part of

their States could be excluded from the

regional haze program. The EPA

disagrees with these comments for two

reasons.

First, the EPA did not base its

proposed applicability provisions only

on the referenced contractor reports.

The EPA based its decision on the

assessments provided by these reports

as well as a number of other studies and

sources of information. Second, as

explained above, EPA believes that all

States must have a visibility SIP to

prevent, at a minimum, future

impairment of visibility. While EPA

agrees that portions of some States may

not need to implement additional

measures, at this time, to improve

visibility impairment in any Class I area,

the EPA believes that more refined

future assessments will be needed to

support such a finding. Additionally,

the EPA believes that a State wishing to

demonstrate that it does not contribute

to visibility impairment in any Class I

area will need to provide information

showing that it has consulted with other

potentially affected States to assist EPA

in assuring that the State’s

demonstration is not contradicted by

evidence presented by other States.

Current monitoring information for

Class I areas shows that all of the

monitored sites in the central and

eastern parts of the country have

visibility impairment levels exceeding

estimated natural conditions for the 20

percent most impaired days, some by

more than 20 deciviews. Although the

degree of impairment varies, the data

demonstrate that no existing site has

reached the goal in section 169A(a)(1) of

the CAA for ‘‘remedying * * * any

existing impairment of visibility.’’ 52

In light of this finding, EPA disagrees

with the commenter who asserted that

because visibility levels in its State are

already ‘‘acceptable,’’ there is no need

for the State to implement a regional

haze program. The section 169A

national goal of the visibility program,

a condition of no human-caused

impairment, does not provide for

judgments of acceptable visibility levels

which are poorer than natural

conditions in Class I areas. Through

adoption of section 169A(a)(1), Congress

established natural visibility conditions

as the overall goal.

The data also show that in the

monitored locations in the central and

eastern United States, sulfate is the key

contributor to visibility impairment,

responsible for between 45–90 percent

of light extinction due to aerosols on the

20 percent most impaired days. This

fact is significant because the broad,

regional scale of long-range transport of

sulfate has already been acknowledged

in many studies done for the acid rain

program. Based on these data, it appears

that although the acid rain program is

expected to improve visibility by

approximately 3 deciviews in the most

impaired Class I areas in the Eastern

United States by 2005,53 further regional

reductions in SO2 emissions may be

needed after the acid rain program is

complete to assure continued visibility

improvement toward the national goal.

Thus, EPA finds it is reasonable to

require SIPs from the States without

Class I areas which are located in the

central and eastern parts of the United

States since many, if not all, are

expected to have sources contributing to

regional loadings of SO2 emissions, even

after implementation of the acid rain

program is completed.

For all of the reasons stated above,

EPA has concluded in today’s final rule

that EPA’s statutory authority and

scientific evidence are sufficient to

require all States to develop regional

haze SIPs to ensure the prevention of

any future impairment of visibility, and

to conduct further analyses to determine

whether additional emission reduction

measures are needed to ensure

reasonable progress in remedying

existing impairment in downwind Class

I areas.

B. Timetable for Submitting the First

Regional Haze State Implementation

Plan (SIP)

This final rule establishes a schedule

setting forth deadlines by which the

States must submit their first regional

haze SIPs and subsequent revisions to

that first SIP. In this unit, we discuss the

deadlines for the first regional haze SIP,

the concerns raised in comments

regarding these deadlines, and recent

legislation affecting the deadlines. The

requirements for periodic revisions to

this first regional haze SIP are discussed

below in unit III.J.

Proposed rule. The proposed rule,

consistent with section 169B(e)(2) of the

CAA, would have required States to

submit revisions to their SIP to address

regional haze within 12 months of the

effective date of the rule. We had

intended that these 12-month SIP
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35723

54 63 FR 46952.

55H.R. Conf. Rep. No. 550, 105th Cong., 2d. Sess.

519 (1998), reprinted in 1998 U.S.C.C.A.N., No. 6

at 196.

56See TEA–21, Section 4102(c)(1).

57We expect that some States will want to move

expeditiously with some designations, leading to

submissions and final action on some areas as early

as late 2002 or early 2003. Where this is the case,

this would lead to earlier regional haze SIP

submittal deadlines as well.

submittals serve as program planning

SIPs in which the States would review

existing regulatory authorities and

provide the framework for a number of

future actions.

Comments received. Commenters

expressed the view that 12 months was

an insufficient time period to meet the

proposed requirements for the program

planning SIP. Moreover, commenters

were concerned that the 12-month SIP

requirement was not well coordinated

with similar program planning for the

new PM2.5 standard.

Transportation Equity Act for the 21st

Century (TEA–21). After the close of the

comment period for the July 1997

proposal, Congress passed the

Transportation Equity Act for the 21st

Century (TEA–21), Public Law 105–178.

The TEA–21 superseded the statutory

requirement for a 12-month SIP

deadline and established a specific

schedule for regional haze SIP

submissions. In a September 3, 1998

notice of availability, EPA provided the

public with an opportunity to comment

on how the regional haze rule should

address the TEA–21 requirements.54

The TEA–21 provisions establish a

timetable for the regional haze SIPs by

first creating certain deadlines for PM2.5

monitoring and area designations, and

then by linking those deadlines to

further deadlines for the regional haze

program. The TEA–21 amendments, in

section 4102(a), require EPA to fund a

PM2.5 monitoring network. In section

4102(b), EPA and States are required to

put this network in place by no later

than December 31, 1999.

Section 4102(c)(1) of TEA–21

establishes deadlines for States to use

the data collected by the network for

purposes of formally designating areas

as attaining the PM2.5 standard or as

nonattainment or unclassifiable. Section

4102(c)(1) states:

(1) The Governors shall be required to

submit designations referred to in section

107(d)(1) of the CAA for each area following

promulgation of the July 1997 PM2.5 national

ambient air quality standard within 1 year

after receipt of 3 years of air quality

monitoring data performed in accordance

with any applicable Federal reference

method for the relevant areas.

Section 4102(c)(2) of TEA–21 contains

the following language which links the

timing requirements for the visibility

program to the PM2.5 designation

process:

(2) For any area designated as

nonattainment for the July 1997 PM2.5

national ambient air quality standard in

accordance with the schedule set forth in this

section, notwithstanding the time limit

prescribed in paragraph (2) of section 169B(e)

of the CAA, the Administrator shall require

State implementation plan revisions referred

to in such paragraph (2) to be submitted at

the same time as State implementation plan

revisions referred to in section 172 of the

CAA implementing the revised national

ambient air quality standard for fine

particulate matter are required to be

submitted. For any area designated as

attainment or unclassifiable for such

standard, the Administrator shall require the

State implementation plan revisions referred

to in such paragraph (2) to be submitted 1

year after the area has been so designated.

The preceding provisions of this paragraph

shall not preclude the implementation of the

agreements and recommendations set forth in

the GCVTC Report dated June 1996.

To accompany the statutory changes

contained in the TEA–21 law, Congress

released a Conference Report. With

respect to the visibility provisions of

TEA–21, the Conference Report states:

The Conferees recognize that the Regional

Haze regulation has not been finalized and

the Administrator of the Environmental

Protection Agency (EPA) is still considering

the views of various stakeholders. The

Conferees agree with EPA’s public statements

that the schedule for the State

Implementation Plan due pursuant to section

169B(e)(2) of the * * * [Clean Air] * * *

CAA should be harmonized with the

Schedule for State Implementation Plan

submissions required for PM2.5 ambient air

quality standard promulgated in July, 1997.55

This new statutory language has two

effects. First, it supersedes the section

169B requirement for EPA to require

States to submit SIPs within 12 months

of the promulgation of today’s final rule.

Second, it spells out a timetable for SIP

revisions that is linked to the dates of

attainment/nonattainment designations

for PM2.5. It is important to note that the

timetable is based on the designation of

areas within a State. Thus, under the

legislation, one State could have

multiple SIP submission deadlines

depending on the dates of designation of

each area within the State. This issue,

and how EPA intends to address it, is

further discussed later in this unit.

According to a Presidential

memorandum dated July 16, 1997, the

EPA and States must collect 3 years of

monitoring data in order to have a

sufficient basis for designations. This

point is reiterated in TEA–21.56 Routine

collection of monitoring data begins in

1999. Hence, we expect the

requirements of TEA–21, section

4102(c)(1), to result in the following:

Submissions of designation requests

by States. States must submit

designations within 1 year of the date

that 3 years of PM2.5 data are available.

Because widespread monitoring for

PM2.5 is being implemented between

January 1999 and December 31, 1999,

we expect 3 years of data to be collected

by December 31, 2001 for most areas

and no later than December 31, 2002 for

the remaining areas. Taking into

account additional time (not more than

6 months) for quality assurance and

certification of the data, we expect 3

years of data to be available for States

to use for designations between July

2002 and July 2003. In the TEA–21

amendments, States have up to 1 year to

submit designations. Thus, we expect

that the required date for submittal of

designations generally will occur

between July 2003 and July 2004.57

EPA action on State designations. The

EPA is required to act upon the

designations no later than 1 year after

the date States are required to submit

the designations, but not later than

December 31, 2005 in any case. If States

submit their designations between July

2003 and July 2004, EPA would be

required to designate areas between July

2004 and July 2005.

For areas designated as attainment or

unclassifiable, the TEA–21 amendments

require that States must submit SIPs for

regional haze within 1 year after EPA

publishes the designations. As a result,

for these areas, regional haze SIPs are

likely to be due generally between July

2005 and July 2006.

For areas designated as nonattainment

for fine particulate matter, the TEA–21

amendments require States to submit

SIP revisions addressing regional haze

‘‘at the same time as States submit SIPs

as required by section 172 of the CAA

implementing the July 1997 revision to

the national ambient air quality

standard for fine particulate matter.’’

Section 172(b) of the CAA requires SIPs

no later than 3 years after EPA publishes

the nonattainment designation. If EPA

designates areas nonattainment between

July 2004 and July 2005, the regional

haze SIPs for areas designated as

nonattainment and the PM2.5

nonattainment SIPs would both be due

no later than the July 2007 to July 2008

timeframe.

The date for startup of PM2.5

monitoring may vary in different parts

of a given State. Accordingly, the EPA

expects that States may not be able to

submit designation requests at the same

time for the entire State. Rather, EPA
35724 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

58See H.R. Conf. Rep. No. 550, 105th Cong., 2d.

Sess. 517.

59The option for regional planning provided by

section 51.308(c) is not available for Alaska,

Hawaii, and the Virgin Islands. Class I areas within

their boundaries are not affected by emissions from

any other State. As a result, regional planning will

not be needed to develop regional haze SIPs for

these areas.

expects that it is possible that

individual ‘‘areas’’ within a given State

may be designated at different times.

Even if areas were all designated at the

same time, in many States some areas

will likely be designated attainment,

with others designated nonattainment.

In either case, the TEA–21 deadlines

would require separate regional haze

SIPs for each of these areas to be

submitted at different times.

While the language in TEA–21

establishing the timetable for

submission of regional haze SIPs is

generally clear, the transportation

legislation does not address the

situation where States are participating

in a regional planning effort that

incorporates numerous areas. On its

face, TEA–21 requires the submission of

separate regional haze SIPs on an areaby-area basis with varying deadlines

that could range over a period of several

years. As noted above, however,

regional haze is the result of emissions

from a number of sources located over

a broad geographic area. Because of the

long-range transport of pollutants

causing regional haze, EPA believes that

well-coordinated regional planning

efforts are needed to make progress

toward natural visibility conditions. As

EPA noted in the September 3, 1998

notice of availability, we do not believe

that Congress intended to inhibit

regional planning efforts by requiring

area-by-area submittals. In light of this,

EPA requested comment on

incorporating an optional approach into

the final rule to facilitate regional

planning.

Notice of availability of additional

information. The optional approach

EPA described in the September 3, 1998

notice of availability would allow States

which commit to participating in

regional planning efforts to postpone

addressing certain of the requirements

of the regional haze program. Under this

approach, States would have the option

to first submit SIPs which contain

commitments to specific integrated

regional planning efforts but which do

not set forth control strategies. States

committing to regional planning would

subsequently submit SIP revisions

containing control strategies for

attainment, unclassifiable, and

nonattainment areas at the same time.

This would allow multiple areas within

a single planning region to have

coordinated deadlines for regional haze

control strategies. In the supplemental

notice, we noted that this approach

could have the effect of delaying control

strategy plan submittal dates for some

areas, but we believe that such an

option will support more effective

coordination between the PM2.5 and

regional haze programs, will support

coordinated regional planning for both

programs, and will be consistent with

the statement of congressional intent.

Comments received. Some

commenters argued that TEA–21 does

not authorize EPA to defer

implementation of the regional haze

program in this way. The basis for this

argument is the claim that the 1-year

deadline in section 169B(e)(2) applies

only to regulations promulgated

pursuant to the report of a visibility

transport commission. These

commenters claim that EPA is obligated

under section 169A to provide for more

expedited implementation of measures

to assure reasonable progress.

The final rule. The regulations made

final today are issued under the

authority of CAA sections 169A and

169B. As discussed in unit II.C above,

EPA in 1980 explicitly deferred issuing

regulations to address regional haze

until our scientific and technical

knowledge was better developed. In

1990, Congress amended the CAA by

adding section 169B. This section

authorizes the establishment of

visibility transport commissions which,

among other things, must issue a report

addressing ‘‘the promulgation of

regulations under [section 169A] to

address long range strategies for

addressing regional haze.’’ Section 169B

further establishes explicit timeframes

in which EPA must, taking into account

any reports of visibility transport

commissions, issue regulations under

section 169A, and in which States must

respond by submitting revised SIPs.

Congress modified the timeframe for SIP

submission in TEA–21 to ensure the

ability of EPA to harmonize the

implementation of today’s final rule

with the requirements for the new PM2.5

NAAQS.58 Today’s final rule carries out

EPA’s obligation under sections 169A

and 169B to issue regulations

addressing regional haze according to

the timeframe as set forth in section

169B as modified by TEA–21.

The final rule includes the deadlines

for SIP submittals set forth in TEA–21

and incorporates an optional set of

requirements for States which commit

to participate in regional planning.

Commenters generally agreed with

EPA’s view in the notice of availability

that it is important to ensure that the

PM2.5 program and regional haze

program are fully integrated. The EPA

believes that the approach taken in the

final rule supports effective

coordination between these programs,

while also facilitating regional planning.

In the final rule, the timetable for SIP

submittals is set forth in section

51.308(b) and (c). Section 51.308(b)

directly codifies the TEA–21 timetable.

Section 51.308(c) provides States that

have committed to participate with

other States in a regional planning

process the option of choosing to defer

submittal of a SIP which addresses the

substantive requirements of the regional

haze program. States are not required to

exercise the option provided by section

51.308(c), but those which do must meet

the deadlines set forth in that section for

submitting a SIP which addresses the

distinct requirements in section

51.308(c) and a SIP revision which

addresses the substantive requirements

of the regional haze program.59

As a first step, States electing to

participate in regional planning must

submit a SIP demonstrating the State’s

ongoing participation in a regional

planning process. This SIP must address

all areas in the State and is due on the

earliest date by which an

implementation plan affecting any area

within the State would be due under the

TEA–21 deadlines. Unless an entire

State is designated as nonattainment,

this SIP will be due 1 year after EPA

designates any area within the State as

attainment or unclassifiable. This SIP

submission must contain a number of

specific elements to demonstrate the

State’s commitment to the regional

planning process and to ensure that by

the date of the SIP submittal, the States

in the regional planning body have

taken the necessary steps to initiate the

regional planning process.

The following briefly summarizes the

required elements of the first SIP

submittal called for under the optional

approach for regional planning:

Need for regional planning. In the

SIP, the State must demonstrate the

need for regional planning. The State

must make this demonstration by

showing that emissions from sources

within the State contribute to visibility

impairment in Class I areas in another

State, or by showing that other States

contribute to visibility impairment in

the Class I areas in the State. The EPA

does not intend for this to be an overly

complex analysis.

Description of regional planning

organization. The State must also

submit a detailed description of the

regional planning process. In its SIP, the

State must show that the participating
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35725

60Pitchford, M. and Malm, W., ‘‘Development

and Applications of a Standard Visual Index,’’

Atmospheric Environment, v. 28, no. 5, March

1994. 61 62 FR 41145.

States have a credible regional planning

process in place which all parties are

committed to follow. We have outlined

general principles for regional planning

organizations in a document entitled

Implementation Guidance for the

Revised Ozone and Particulate Matter

(PM) National Ambient Air Quality

Standards (NAAQS) and the Regional

Haze Program, which discusses features

of effective regional planning

organizations, including a discussion of

organization and representation issues,

issues related to developing workplans

and schedules, and issues related to

ensuring that technical efforts are

consistent. This document is available

on the internet at http://www.epa.gov/

ttn/oarpg/t1pgm.html.

Enforceable commitment to submit

coordinated control strategy by 2008.

The regional planning SIP must include

provisions requiring the State to submit

a SIP revision meeting all of the

requirements of the regional haze rule.

This SIP revision is due by the latest

date an area within the planning region

would be required to submit an

implementation plan under TEA–21,

but in no event any later than December

31, 2008. The SIP must require that the

SIP revision is developed in

coordination with the other States in the

regional planning body and that it fully

addresses the recommendations of that

body.

List of BART-eligible sources. The

State must identify those sources from

one of 26 source categories and placed

into operation between 1962 and 1977

that are potentially subject to BART.

This information will enable the State

and regional planning organization to

begin evaluating options for meeting the

BART requirement or for implementing

an emissions trading program or

alternative measure that achieves greater

reasonable progress.

Summary of timetable for submission

of the first regional haze SIPs. The

following table is a summary of the

deadlines for submitting the first

regional haze SIPs.

For this case . . . . . . States must submit the first regional

haze SIPs no later than: . . . and the SIP must meet . . .

Areas designated as attainment or

unclassifiable for PM2.5.

1 year after EPA publishes the designation

(generally 2004–2006).

ALL requirements of section 51.308(d) and

(e).

Areas designated as nonattainment for PM2.5 ... At the same time as PM2.5 SIPs are due

under section 172 of the CAA. (That is, 3

years after EPA publishes the designation,

generally 2006–2008).

ALL requirements of section 51.308(d) and

(e).

States participating in multistate regional planning efforts for combined attainment and nonattainment areas.Two phases: .....................................................

Commitment to regional planning due 1 year

after the EPA publishes the first designation

for any area within the State, and.

The regional planning requirements listed in

section 51.308(c).

Complete implementation plan due at the

same time as PM2.5 SIPs are due under

section 172 of the CAA. (That is, 3 years

after EPA publishes the designation).

The ‘‘core requirements’’ listed in section

51.308(d) and BART requirements in section 51.308(e).

States following the recommendations of the

GCVTC, as contained in section 51.309 of

the final rule.

December 31, 2003 ......................................... SIPs must meet the specific provisions for

Grand Canyon Transport Region States listed in section 51.309.

C. Tracking Deciviews and Emissions

Reductions

Visibility impairment is caused by

particles and gases in the atmosphere.

Some particles and gases scatter light,

while others absorb light. The net effect

is called ‘‘light extinction.’’ The result of

these processes is a reduction of the

amount of light from a scene that is

returned to the observer, creating a hazy

condition.

Proposed rule. In the proposal, EPA

established a regulatory framework by

which a State would establish a

‘‘reasonable progress target’’ for each

Class I area within its borders for the

purpose of improving visibility on the

worst visibility days over the next 10 or

15 years. The States would implement

emission management strategies to

improve visibility in these Class I areas.

The proposal also called for the States

to monitor progress in improving

visibility over time. The EPA proposed

that visibility targets and tracking of

visibility changes over time be

expressed in terms of the ‘‘deciview’’

haze metric. The proposal also called for

the tracking of pollutant emissions to

supplement the tracking of monitored

visibility changes for use in periodically

reviewing State progress in achieving

visibility targets. The proposal included

the definition of the deciview metric for

tracking visibility. The proposal also

called for a review of emissions

reductions achieved as part of the longterm strategy.

Deciview. The proposal explained that

the deciview is an atmospheric haze

index that expresses changes in

visibility. This visibility metric

expresses uniform changes in haziness

in terms of common increments across

the entire range of visibility conditions,

from pristine to extremely hazy

conditions.60 Because each unit change

in deciview represents a common

change in perception, the deciview scale

is like the decibel scale for sound. The

proposal also stated that ‘‘A one

deciview change in haziness is a small

but noticeable change in haziness under

most circumstances when viewing

scenes in Class I areas.’’ 61

The proposal discussed that an

advantage to using the deciview over

other scales is that it can be used to

express changes in visibility impairment

in a way that corresponds to human

perception in a linear, or one for one,

manner. For example, this metric is

designed such that a change of 3

deciviews in a highly impaired

environment would be perceived as

roughly the same degree of change as a

3 deciview change in a relatively clear

environment. As noted in the preamble

to the proposed regulation, the deciview

is mathematically related to other

common metrics used to describe

visibility: the light extinction coefficient

and visual range. However, the deciview

metric can be used to compare changes

in perception in a way that the other

two metrics cannot. This feature makes

the deciview a more useful metric for

regulatory purposes. For example, a 5-
35726 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

62Tracking of visibility is addressed in section

51.308(d) and 51.308(g). Tracking of emissions

reductions is addressed in section 51.308(g).

63Section 169B(e)(1).

64Pitchford, M. and Malm, W., ‘‘Development

and Applications of a Standard Visual Index,’’

Atmospheric Environment, V. 28, no. 5, March

1994.

65U.S. EPA, Air Quality Criteria for Particulate

Matter, Research Triangle Park, NC, National Center

for Environmental Assessment. Office of Research

and Development, July 1996.

66U.S. Environmental Protection Agency. Review

of the National Ambient Air Quality Standards for

Particulate Matter: Policy Assessment of Scientific

and Technical Information. OAQPS Staff Paper.

Office of Air Quality Planning and Standards. July

1996.

67Sisler, J., et al., Spatial and Seasonal Patterns

and Long-Term Variability of the Composition of

the Haze in the United States: An Analysis of Data

from the IMPROVE Network. Cooperative Institute

for Research in the Atmosphere, Colorado State

University, 1996. See also Sisler, J., et al., Spatial

and Temporal Patterns and the Chemical

Composition of the Haze in the United States: An

Analysis of Data From the IMPROVE Network,

1988–1991, Fort Collins, CO, 1993.

68National Research Council, Protecting

Visibility in National Parks and Wilderness Areas,

1993, p. 354.

69Congressional Research Service, Regional Haze:

EPA’s Proposal to Improve Visibility in National

Parks and Wilderness Areas, November 17, 1997, p.

17.

mile change in visual range can in some

cases be very significant, such as from

5 to 10 miles in an impaired

environment (equal to a change of 6.9

deciviews), whereas a 5-mile change

may not be perceptible in a less

impaired environment, such as from 95

to 100 miles (equal to a change of 0.5

deciviews). The following sections

discuss the comments received on

specific issues and how such issues are

addressed in the final rule.

Tracking emissions versus visibility.

Many commenters supported the use of

the deciview metric to track changes in

visibility improvement as a key aspect

of the program. These commenters

agreed with EPA’s proposal that under

a visibility-oriented program, progress

in fact should be tracked in terms of a

visibility-based metric. Others felt the

program could be successfully

implemented by tracking emissions only

because this approach would not be

greatly affected by meteorological

variations as would an approach based

on ambient monitoring.

The final rule provides for the

tracking of both visibility improvement

and emissions reductions.62 The final

rule presents visibility improvement

and tracking of emissions as linked

elements of the program. The EPA has

retained the use of the deciview metric

for tracking changes in visibility. The

EPA believes the tracking of actual

visibility improvements is necessary to

be responsive to the goals of the CAA.

Section 169A(a) of the CAA sets forth

the national goal of the ‘‘prevention of

any future, and the remedying of any

existing, impairment of visibility in

Class I areas which impairment results

from manmade air pollution.’’ The CAA

also requires EPA to establish

regulations to be implemented by the

States to ensure that ‘reasonable

progress’ is made toward the national

goal. In addition, section 169B(e) of the

CAA calls for EPA to carry out its

‘‘regulatory responsibilities under

section 169A, including criteria for

measuring ‘reasonable progress’ toward

the national goal.’’ 63

The EPA believes that tracking of

emissions reductions is also an

important component of the regional

haze program. The mechanism for

achieving improvements in visibility

will be the implementation of

enforceable emissions reduction

measures that have been adopted as part

of the SIP. Tracking emissions will

provide a good indicator of whether

adopted measures are reducing

emissions and is thus a useful indicator

of progress in reducing visibility

impairment. The tracking of emissions

without concurrently tracking changes

in visibility, however, would be

problematic because of the variable

effect on visibility of each of the

principal constituents of PM, the more

significant light scattering efficiency of

fine PM versus coarse PM, and the

generally greater effect of nearby versus

distant sources on visibility impairment.

Since the national goal is expressed in

terms of air quality (i.e., visibility)

rather than emissions, we believe that it

is very important to require the

quantitative tracking of visibility

impairment as an integral element in

measuring reasonable progress. Because

ambient monitoring data are subject to

meteorological fluctuations, EPA

designs standards and requirements for

analysis of monitoring data to limit the

effects of unusual meteorological events.

For regional haze, we have provided in

this final rule for the tracking of

visibility trends based on 5-year

averages of annual deciview values for

the most impaired and least impaired

days. We believe that this approach

responds to commenters’ concerns

about significant unusual fluctuations in

annual average values for the best and

worst days due to unusual

meteorological conditions in any

particular year. However, it is also

important to note that EPA has long

held that normal meteorological

variations should be explicitly

accounted for in air quality analyses and

control strategy design. Air quality

improvement plans should be able to

assure protection of public health and

welfare under the normal and

foreseeable range of meteorological

conditions.

Tracking visibility in deciviews. Some

commenters disagreed with the use of

the deciview to measure changes in

visibility, claiming that the deciview

metric has not been adequately

reviewed for use in a regulatory

program. The EPA disagrees with this

assertion. The EPA believes the

deciview metric has been adequately

reviewed for use in the regional haze

program. The deciview concept was

introduced in 1994 in an article

appearing in the peer-reviewed journal

Atmospheric Environment.64 It was

presented in the 1996 Criteria Document

for the PM NAAQS as a valid metric for

characterizing visibility impairment.65

The EPA also recognized the deciview

as an appropriate metric for regulatory

purposes in chapter 8 of the 1996 Staff

Paper for the PM NAAQS review.66 Both

of these documents were reviewed and

accepted by the Clean Air Scientific

Advisory Committee. Visibility

conditions at Class I areas have been

characterized in terms of deciview in

summary reports on the IMPROVE

visibility monitoring network.67

The EPA also supports use of the

deciview metric because it satisfies one

of the recommendations of the NAS

Committee on Haze in National Parks

and Wilderness Areas. In its 1993 report

on visibility, the NAS recommended the

development of an index that takes into

account both measurement of physical

changes (i.e., changes in air quality)

with elements of human perception.68

Further, a report on the regional haze

proposal by the Congressional Research

Service found that the deciview index

‘‘conforms closely’’ 69 to the NAS

recommendation cited above.

Some commenters stated that the final

rule should not suggest that a one

deciview change is the threshold of

perception in all cases for all scenes.

The EPA agrees with the comment that

a one deciview change should not be

considered the threshold of perception

in all cases for all scenes. The EPA

believes that visibility changes of less

than one deciview are likely to be

perceptible in some cases, especially

where the scene being viewed is highly

sensitive to small amounts of pollution.

The EPA also acknowledges the

technical point made by some

commenters that for other types of

scenes with other site-specific
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35727

70For example, where the sight path to a scenic

feature is less than the maximum visual range.

71See Sisler, et al., Spatial and Seasonal Patterns

and Long-Term Variability of the Composition of

the Haze in the United States: An Analysis of Data

from the IMPROVE Network. Cooperative Institute

for Research in the Atmosphere, Colorado State

University, 1996.

72 Id.

conditions,70 a change of more than 1

deciview might be required in order for

the change to be perceptible. However,

EPA wishes to emphasize that the

overall goal of the regional haze

program is not to track changes in

visibility for only certain vistas at a

specific Class I area. Rather, the program

is designed to track changes in regional

visibility for the range of possible views

of sky and terrain found in any Class I

area, and to assure progress toward the

national goal. For this purpose, EPA

supports the use of the deciview metric

as calculated from ambient monitoring

data for tracking changes in regional

visibility. The monitoring network is

not designed to track changes in

visibility for specific views in each

Class I area. Rather, the network is

designed to characterize visibility

conditions that, for each site, are

representative of a fairly broad

geographic region. The EPA believes

this approach is consistent with the

nature of regional haze, which is

defined as a uniform haze caused by

numerous sources covering a broad area.

Thus, although a 1 deciview change

may not be the threshold of perception

in all situations, the fundamental

advantage of using the deciview

remains: the deciview metric expresses

uniform changes in haziness in terms of

common increments across the entire

range of visibility conditions, from

pristine to extremely hazy conditions.

The metric provides a useful means of

expressing changes in visibility caused

by changes in air quality while also

providing a scale that relates visibility

to perception. The final rule maintains

the deciview as the principle visibility

metric used in establishing reasonable

progress goals, in defining baseline,

current, and natural conditions, and in

tracking changes in visibility conditions

over time. States may choose to express

visibility changes in terms of other

metrics, such as visual range or light

extinction, as well as in terms of

deciview. The definition in the final

rule was modified slightly to provide

additional clarity.

Light extinction calculated from

aerosol data. Some other commenters

did not support EPA’s proposed

approach to calculating light extinction

based on monitored fine particle data

(referred to as ‘‘reconstructed light

extinction’’ in the proposal). These

commenters preferred other methods,

such as direct measurement of light

scattering or light extinction with an

optical device. While such methods are

desired in comprehensively monitoring

visibility impairment, the EPA supports

the use of a common approach for

calculating visibility changes based on

monitored fine particle data as the

primary monitoring method for tracking

visual air quality.

Such an approach has been

established and implemented for many

years by the IMPROVE Steering

Committee. The IMPROVE approach

uses a set of standard assumptions,71

which have been tested and found to be

reasonable, in calculating light

extinction and deciviews from changes

in air quality. Two important aspects of

the approach are: (1) Standard rates of

light extinction per unit mass of

visibility-impairing pollutants (e.g.,

sulfate, nitrate, organic carbon,

elemental carbon, and crustal material);

and (2) standard effects of humidity on

sulfate and nitrate.

Through extensive analysis of

empirical data, a value (or ‘‘dry

extinction coefficient’’) has been

developed for each aerosol component

which represents the amount of light

extinction (expressed in inverse

megameters) caused by each microgram/

m3 of that component. Light extinction

is calculated by multiplying the aerosol

mass for each component by its

extinction coefficient and summing the

products. Because sulfates and nitrates

become more efficient at scattering light

as humidity increases, the values for

these two components are also

multiplied by a relative humidity

adjustment factor. It has been shown

that annual and seasonal light

extinction values developed according

to this method correlate well with

averages of optical measurements of

light extinction for the same locations.72

The EPA plans to issue future guidance

describing the details of calculating

visibility changes in this manner and

tracking visibility over time.

Although light extinction can be

measured directly by certain optical

devices (i.e., transmissometers and

nephelometers), EPA supports an

approach based on the mass of PM

components derived from ambient

monitoring for calculating light

extinction for two main reasons. First,

this approach provides for the tracking

of actual changes in the components of

air pollution, and the information

obtained from analysis of the chemical

composition of PM is critical to the air

quality modeling and strategy

development processes. By

understanding the chemical

composition of particulate matter, we

can better define the manmade and

natural components contributing to

overall light extinction. Second, direct

measurements of visibility from some

optical instruments (e.g.,

transmissometer) are more frequently

disrupted by precipitation events (i.e.,

rain or snow) than are aerosol

measurements.

For all of the reasons discussed above,

the final rule provides for the tracking

of visibility and emissions reductions.

The deciview will be the principal

visibility metric for use in implementing

the regional haze program. The

deciview will be used for expressing

reasonable progress goals, defining

baseline, current, and natural

conditions, and tracking changes in

visibility conditions over time. The

definition of deciview in the final rule

in section 51.301(bb) was modified

slightly to provide additional clarity and

state that deciview values are to be

derived from calculated light extinction

based on aerosol measurements in

accordance with EPA guidance.

D. Regional Haze Implementation Plan

Principles

Section 169A of the CAA calls for

States to develop implementation plans

ensuring reasonable progress toward the

national goal, including emission limits,

schedules of compliance and other

measures as necessary. At a minimum,

the CAA calls for SIPs to include a longterm strategy and provisions for BART

for certain major stationary sources. We

would like to emphasize several

overarching themes for the specific

implementation plan requirements in

the final rule:

• Regional haze regulations and State

implementation plans must address all

of the statutory requirements outlined in

169A and 169B of the CAA. Regional

haze requirements must address a

number of specific statutory

requirements, including ‘‘criteria for

reasonable progress,’’ long-term

strategies addressing all types of sources

and activities, and best available retrofit

technology for certain stationary

sources. The implementation plan

requirements in the final rule are

designed to ensure that all of these

statutory requirements will be met.

• Tracking ‘‘reasonable progress’’

should involve the tracking of both

emissions and visibility improvement.

Regional haze implementation plans

must include provisions for tracking the

implementation of enforceable emission

management strategies designed to make

reasonable progress toward the national
35728 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

73National Research Council, Committee on Haze

in National Parks and Wilderness Areas, Protecting

Visibility in National Parks and Wilderness Areas,

National Academy Press, 1993.

visibility goal. Emission control

measures will be the component that

will be enforceable to ensure reasonable

progress. Measuring reasonable progress

should involve tracking the actual

emissions achieved through

implementation of such strategies, and

the tracking of visibility for the most

impaired and least impaired days using

established monitoring and data

analysis techniques.

• Strategies for improving visibility

should address all types of sources.

Section 169A provides for State longterm strategies to address all types of

sources and activities emitting

pollutants that contribute to visibility

impairment in Class I areas, including

stationary, mobile, and area sources.

Implementation plans also must give

specific attention to certain stationary

sources built between 1962 and 1977

and provide for meeting the BART

provisions for these sources.

• Successful implementation of the

regional haze program will involve longterm regional coordination among

States. Pollution affecting the air quality

in Class I areas can be transported long

distances, even hundreds of kilometers.

Therefore, States will need to develop

strategies in coordination with one

another, taking into account the effect of

emissions from one jurisdiction to air

quality in another. In addition, as noted

by the NAS study, ‘‘achieving the

national visibility goal will require a

substantial, long-term program.’’ 73

Accordingly, the regional haze program

requires the periodic review by each

State of whether ‘‘reasonable progress’’

is being achieved and revisions of

implementation plans as needed to

continue progress toward the national

visibility goal.

E. Determination of ‘‘Baseline,’’

‘‘Natural’’ and ‘‘Current’’ Visibility

Background. The fundamental goal of

the visibility program, as provided by

Congress, is the prevention of future

visibility impairment and the remedying

of existing impairment in Class I areas.

Thus, the regional haze program must

track progress toward the national goal.

In order to facilitate this tracking

process, the proposed rule required each

State having one or more Class I areas

to establish, and update as necessary,

three important visibility parameters for

the best and worst visibility days at each

Class I area within the State. Each

parameter is discussed in detail below.

• Baseline conditions—Baseline

conditions represent visibility for the

best and worst days at the time the

regional haze program is established.

Baseline conditions are calculated using

multiyear averaging.

• Natural conditions—As specified in

the CAA, estimated natural conditions,

or the visibility conditions that would

be experienced in the absence of

human-caused impairment, constitute

the ultimate goal of the program. Under

the regional haze program, natural

conditions need to be estimated for the

20 percent best and worst days.

• Current conditions—Current

conditions for the best and worst days

are calculated from a multiyear average,

based on the most recent years of

monitored data. This value would be

revised at the time of each periodic SIP

revision, and would be used to

illustrate: (1) The amount of progress

made since the last SIP revision, and (2)

the amount of progress made from the

baseline period of the program.

Baseline Conditions

Proposed rule. The preamble to the

proposal discussed an approach for

determining baseline visibility

conditions for the haziest 20 percent

and clearest 20 percent of days that

would allow using a minimum of 3

years of monitored data, and up to a

maximum of 9 years of data.

Comments received. The EPA

received some comments suggesting that

it would be more equitable to use a

standardized time period to establish

baseline values for all Class I areas

across the country. Other commenters

supported the use of baseline values

based on a varying number of years from

site to site. Some commenters also

supported the establishment of baseline

conditions based on a period of time

longer than 3 years because a 3-year

period could be significantly influenced

by unique meteorological

circumstances.

Final rule. After considering public

comments on the baseline issue, EPA

has determined that the most

appropriate ‘‘baseline period’’ would be

a fixed, 5-year period extending from

calendar year 2000 through calendar

year 2004. The EPA concluded that a

standard baseline period provides for

greater national consistency in

establishing this important value, and

therefore, is preferable to a provision

allowing the baseline period to be a

variable number of years. Using a

common number of years and data

points to calculate the baseline value for

each site is consistent with fundamental

statistical principles and will provide

for easy comparison of data from

multiple sites as the program is

implemented.

The EPA also concluded that it would

be preferable to have a baseline value

based on more than 3 years in order to

establish a more robust baseline value.

The EPA agrees with commenters that a

5-year period, rather than a 3-year

period, provides for a more stable

treatment of the inherent variability in

emissions and meteorology. This

approach decreases the probability that

the baseline period will be unduly

affected by unusual or

nonrepresentative events.

In deciding upon the specific baseline

period of 2000–2004, the Agency took

into account the fact that EPA has

obtained funding to provide several

hundred monitors to the States for the

purposes of characterizing PM2.5

concentrations in urban and rural areas

nationally. In accordance with the part

58 monitoring provision enabling

IMPROVE protocol aerosol monitors to

be used to characterize PM2.5 conditions

at background and transport sites, the

IMPROVE network will be expanding

from 30 to more than 100 sites by the

end of 1999 in order to characterize both

background PM2.5 levels and visibility

impairment levels in Class I areas. Thus,

EPA concluded that the baseline period

should begin in 2000, after monitoring

coverage for Class I areas is expanded

significantly.

The approach to calculating baseline

values will also provide for more stable

values because the frequency of

monitoring samples in the IMPROVE

network will increase in 1999 to one

sample every 3 days. In this way, the

frequency of sampling for IMPROVE

will be consistent with the PM2.5

monitoring approach. Thus, annual

values should become more robust since

17 percent more samples will be

collected each year. Baseline conditions

must be determined in terms of

deciviews for the years 2000–2004 for

the ‘‘most impaired days’’ and the ‘‘least

impaired days.’’ The final rule defines

these values as the average of the 20

percent of monitored days with the

highest or lowest light extinction values,

expressed in deciviews. The EPA will

issue guidance for calculating baseline

visibility conditions based on ambient

monitoring data. The baseline value is

determined by calculating the average

deciview value for the 20 percent most

(or least) impaired days for each of the

5 years (2000 through 2004), and by

averaging those five values.

The final rule also calls for baseline

conditions to be established by the State

for any Class I area without on-site

monitoring by using ‘‘representative’’

monitoring data for the site. In the SIP,

the State will need to provide an

adequate demonstration supporting the
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35729

74 Interim Air Quality Policy on Wildland and

Prescribed Fires, U.S. EPA, Office of Air Quality

Planning and Standards, May 1998.

75See unit III.B. for a detailed discussion of the

TEA–21 provisions and their affect on the timing

for implementation of the regional haze program.

76See National Acid Precipitation Assessment

Program. Acid Deposition: State of Science and

Technology. Report 24, Visibility: Existing and

Historical Conditions—Causes and Effects, Table

24–6. Washington, DC. 1991.

77The NAPAP estimates were cited in both the

Criteria Document and EPA Staff for the PM

NAAQS.

use of any ‘‘representative’’ data. The

EPA will issue guidance to help the

States address this issue. The IMPROVE

Steering Committee (comprised of

representatives from EPA, States, and

FLMs) is working to develop acceptable

criteria to configure the expanded

visibility monitoring network in such a

way that virtually all Class I areas will

either have an aerosol monitor or will be

characterized by a ‘‘representative’’ site.

The IMPROVE Steering Committee,

including State representatives, will

complete the process for identifying

representative sites before monitoring

for the expanded network begins in the

year 2000. For this reason, it is expected

that most States needing to rely on

representative data from another site

will be able to meet the requirement of

section 51.308(d)(4) by referencing the

Visibility Monitoring Guidance

Document, which will be released

shortly after promulgation of this rule,

and other technical support materials

developed by the IMPROVE Steering

Committee to support the determination

of representative sites.

Finally, States that submit SIPs for

regional haze by 2003 under section

51.309 (further discussion in unit IV)

must determine baseline conditions

based on the most recent 5-year period

for which monitoring data are available

for the Class I area. For an area without

monitoring data, the State may use data

from another representative Class I area.

Natural Visibility Conditions

Proposal. The proposed rule called for

each State having a Class I area, in

consultation with the appropriate FLMs,

to: (1) Develop a procedure to estimate

natural conditions for the 20 percent

most impaired and least impaired days

at each Class I area within the State; and

(2) provide this estimate with the State’s

first SIP revision for regional haze (in

the 2003–2005 timeframe as stated in

the proposal). The estimates for natural

conditions would be expressed in

deciviews. The preamble cited as a

default annual average, estimates of

natural visibility that were included in

the 1991 NAPAP chapter on visibility.

When converted to deciview values,

these annual average estimates are 9.6

deciviews in the Eastern United States

and 5.3 deciviews in the Western

United States.

Comments received. A number of

commenters noted that there are several

factors which can make the

determination of natural conditions

difficult. For example, organic aerosols

resulting from biogenic sources,

windblown dust, and natural causes of

fire all contribute to natural visibility

conditions. Several commenters

emphasized the difficulty in

determining the estimated contribution

of naturally-caused fire to natural

conditions. Some commenters suggested

that EPA provide guidance on how to

estimate natural conditions.

Final rule. The EPA understands that

estimating natural visibility conditions

can involve many technically complex

issues. The EPA is committed to

working with the States, tribes, and

FLMs on this issue to develop technical

guidance on estimating natural visibility

conditions. The EPA expects that these

estimates may be refined over time. In

addition, after the regional haze rule is

promulgated, and in advance of SIP due

dates, EPA plans to revise the Interim

Air Quality Policy on Wildland and

Prescribed Fires 74 to address a number

of issues, including the contribution of

fire to natural visibility conditions.

Consistent with the proposal, the final

rule retains the requirement that each

State provide an adequate estimate of

natural visibility conditions for best and

worst visibility days in each Class I area

within the State. These estimates will be

due at the time the State submits its

initial control strategy SIP for regional

haze. However, because the requirement

for a SIP revision within 12 months of

promulgation has been overridden by

the provisions of TEA–21, there no

longer is a requirement for States to

separately submit to EPA recommended

procedures for estimating natural

conditions in advance of their control

strategy SIPs.75

The EPA recommends that the States

work closely with the FLMs, tribes, and

EPA in developing and documenting in

their SIPs appropriate methods for

estimating natural conditions. Estimates

of natural visibility conditions are

needed to aid all interested parties,

including the general public, in

understanding how ‘‘close’’ or ‘‘far’’ a

particular Class I area is in relation to

the ultimate goal of the program.

Understanding the estimated relative

contributions of natural PM constituents

(such as organic carbon and crustal

material) also can help the States and

tribes in understanding the extent of the

contribution from manmade

components, and thus can help in

designing appropriate emission

management strategies in the future.

With each subsequent SIP revision, the

estimates of natural conditions for each

Class I area may be reviewed and

revised as appropriate as the technical

basis for estimates of natural conditions

improve.

The EPA believes that, as a starting

point, it will be appropriate to derive

regional estimates of natural visibility

conditions by using estimates of natural

levels of visibility-impairing

pollutants 76 in conjunction with the

IMPROVE methodology for calculating

light extinction from measurements of

the five main components of fine

particle mass (sulfate, nitrate, organic

carbon, elemental carbon, and crustal

material). By using this approach with

appropriate assumptions for annual

average relative humidity, EPA

estimates natural conditions for the

worst visibility days to be

approximately 11–12 deciviews in the

east and 8 deciviews in the west. The

EPA supports use of these estimating

techniques as a valid starting point

because they rely on peer-reviewed

estimates of the natural composition of

fine particle mass,77 and analysis of data

from the IMPROVE program’s wellestablished approach, refined over the

past 10 years or more, for calculating

light extinction from monitored PM

constituents.

Because these values are expressed in

regional terms only, further refinement

of these estimates will need to take

place in the future on a site-specific

basis. However, because current

conditions at most Class I areas with

existing IMPROVE monitoring exceed

the above estimates by at least several

deciviews (with some of the more

impaired Class I areas having values

that exceed estimated natural conditions

by 20 deciviews or more), EPA does not

believe that such refined values are

necessary for the initial 10-year program

implementation period. As the

difference between current and natural

conditions for a particular Class I area

becomes smaller, it will be important to

develop more precise techniques for

estimating natural conditions.

Current Conditions

Proposal. The proposed rule required

the State to revise its long-term strategy

every 3 years and to compare current

conditions to the visibility conditions

existing at the time of its previous longterm strategy revision. Current

conditions would be established for the

most impaired and least impaired days,

and would be expressed in deciviews.
35730 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

78See the section on Baseline Conditions for a

discussion of the rationale for selecting a 5-year

period.

Comments received. Many

commenters supported EPA’s approach

to periodic tracking of changes in

visibility to determine reasonable

progress. Some commenters felt that

averaging 5 years of data, rather than 3,

would be preferable.

Final rule. Section 51.308(f)(1) of the

final rule retains the requirement for

each State, at the time of any SIP

revision, to determine the current

visibility conditions for the most

impaired and least impaired days for

each Class I area within the State.

Current conditions are to be based on

the 5 most recent years of monitoring

data available at the time a SIP revision

or progress report is submitted. The

approach for calculating current

conditions is similar to the approach for

calculating baseline conditions

discussed above: the value is

determined by calculating the average

for the 20 percent most impaired days

for each of the 5 most recent years for

which quality-assured data are

available, and then by calculating the

average of those five values.78

Sections 51.308(f)(1) and 51.308(g)(3)

of the final rule also require the State to

calculate the difference between current

conditions and several other parameters

so that this information can be taken

into account when the State is revising

its SIP and considering new reasonable

progress goals. A discussion of these

calculations is provided in unit III.J of

this preamble addressing periodic SIP

revisions and progress reports.

Summary

The following summary table further

illustrates the uses of ‘‘baseline,’’

‘‘natural,’’ and current conditions in the

regional haze program.

Term What does it mean? How is it used in the regional haze program?

‘‘Baseline conditions’’ ......................................... Visibility (in deciviews) for the 20 percent

most-impaired days, and for the 20 percent

least-impaired days, for the years 2000

through 2004.

‘‘Baseline’’ conditions are used in two ways:

(1) For the first regional haze SIPs, due in

about 2006–2008, baseline conditions are

the reference point against which visibility

improvement is tracked.

(2) For subsequent SIP updates (in the year

2018 and every 10 years thereafter), baseline conditions are used to calculate

progress from the beginning of the regional

haze program.

‘‘Natural conditions’’ ........................................... The level of visibility (in deciviews) for the 20

percent most-impaired days, and for the 20

percent least-impaired days, that would

exist if there were no manmade impairment..

‘‘Natural conditions’’ represents the absence

of visibility impairment due to humancaused emissions, the ultimate goal of the

regional haze program.

‘‘Current conditions’’ ........................................... ‘‘Visibility (in deciviews) for the 20 percent

most-impaired days, and for the 20 percent

least-impaired days, for the most recent 5-

year period.

For the initial planning SIPs, ‘‘current’’ and

‘‘baseline’’ conditions are the same.

For subsequent 5-year progress reports, ‘‘current conditions’’ describe the amount of

progress that has been made at the midcourse review point halfway through an implementation cycle.

For subsequent comprehensive regional haze

SIPs (beginning in 2018 and every 10 years

thereafter), ‘‘current conditions’’ will be used

to show how much progress has been

made relative to the ‘‘baseline,’’ and will

serve as the reference point for tracking

progress for the next implementation period.

F. Reasonable Progress Goals

The previous section discussed three

important visibility parameters for

tracking ‘‘reasonable progress’’ toward

the national visibility goal. In this

section, EPA describes the requirements

of section 51.308(d)(1) of the final rule

for States to establish ‘‘reasonable

progress goals’’ for each Class I area

within the State. In addition, this

section also discusses important

analyses and other factors for States to

take into consideration in setting these

goals.

Proposed rule. In the proposed rule,

EPA presented a framework for a longterm program under which continued

progress would be achieved in Class I

areas toward the national visibility goal.

The EPA proposed presumptive

‘‘reasonable progress targets,’’ expressed

in terms of deciviews, for the purposes

of improving visibility on the 20 percent

worst days and allowing no degradation

of visibility on the 20 percent best days.

Two options were presented for the

presumptive target for the most

impaired days: (1) A rate of

improvement equivalent to 1.0 deciview

over a 10-year period, and (2) a rate of

improvement equivalent to 1.0 deciview

over a 15-year period. For the least

impaired days, EPA proposed a target of

no degradation, defined as less than a

0.1 deciview increase.

The EPA noted that the 10- and 15-

year time periods for tracking

improvement were consistent with

section 169A(b)(2)(B), which calls for

States to develop long-term strategies

covering 10 to 15 years. The EPA also

emphasized the importance of achieving

a perceptible change in visibility over

the time period of a long-term strategy.

In addition, EPA stated that gradual

improvements in visibility as defined by

reasonable progress targets were

consistent with the GCVTC definition of

reasonable progress, which is

‘‘achieving continuous emissions

necessary to reduce existing impairment

and attain steady improvement of

visibility in mandatory Class I areas.
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35731

79 GCVTC Report, June 1996, p. x.

80See CA A section 169A(g)(1) and 169A(g)(2).

See also 62 FR 41145–41148. 81See section 51.308(d)(1).

82U.S. EPA, Effects of the 1990 Clean Air Act

Amendments on Visibility in Class I Areas: An EPA

Report to Congress. Office of Air Quality Planning

and Standards, EPA–452/R–93–014, 1993.

83Calculated by dividing 3 deciviews (per 10

years) into an average of 18 deciviews away from

Continued

* * *’’ 79 As noted in unit III.C., EPA

also proposed to track progress in

relation to the targets through the use of

monitored air quality data and

calculation of light extinction values

from this aerosol data.

The proposal also provided a process

by which a State could establish

alternate reasonable progress targets,

expressed in deciviews, provided the

State justified the alternate target based

on a review of the relevant statutory

factors.80 These factors are:

• The costs of compliance;

• The time necessary for compliance;

• The energy and nonair quality

environmental impacts of compliance;

and

• The remaining useful life of any

existing source subject to such

requirements.

Comments received. A number of

commenters advocated a faster rate of

improvement than the proposed

presumptive rate of 1 deciview every 10

or 15 years since, as proposed, they

claimed it could take more than 200

years to reach the national visibility goal

in some eastern locations. They felt that

this rate of progress should not be

considered ‘‘reasonable.’’ Many of these

commenters supported a rate of

improvement for the worst days equal to

10–20 percent of the current deciview

value (i.e., 3–6 deciviews per 10 years

in an average eastern location with a

worst day value of 30 deciviews, and

1.5–3.0 deciviews for an average

southwestern location with a worst day

value of 15 deciviews). A number of

other commenters interpreted the

proposed rule as requiring an inflexible

visibility ‘‘standard’’ of 1 deciview

improvement every 10 or 15 years. They

maintained that such a standard would

be infeasible to achieve in some areas of

the country, and that EPA had failed to

justify such a presumption through an

analysis of the statutory factors in

section 169A(g). These commenters

wanted the States to have greater

flexibility in setting visibility goals.

Some commenters stated that 1

deciview is not the threshold of

perception in all situations, and that for

this reason the one deciview

presumptive target in the proposal

should be dropped. Other commenters

asserted that the no degradation target

for the best visibility days would

prevent new source growth in some

areas. Some commenters also opposed

the presumptive target because of the

concern that a State could be subject to

a citizen lawsuit for not meeting a

reasonable progress target.

Final rule. In considering how to

address the reasonable progress target

issue in the final rule, EPA was mindful

of the balance that must be maintained

between the need for strategies that will

achieve meaningful improvements in air

quality and the need to provide

appropriate flexibility for States in

designing strategies that are responsive

to both air quality and economic

concerns. After considering the

comments on the ‘‘presumptive target’’

issue, EPA has revised the rule to

eliminate ‘‘presumptive targets.’’ There

is no presumptive target that States are

required to meet to achieve reasonable

progress. States have flexibility in

determining their reasonable progress

goals based on consideration of the

statutory factors. However, as discussed

below, the final rule requires States to

conduct certain analyses to ensure that

they consider the possibility of setting

an ambitious reasonable progress goal,

one that is aimed at reaching natural

background conditions in 60 years.

The final rule calls for States to

establish ‘‘reasonable progress goals,’’ 81

expressed in deciviews, for each Class I

area for the purpose of improving

visibility on the haziest days and not

allowing degradation on the clearest

days over the period of each

implementation plan or revision. The

EPA believes that requiring States to

establish such goals is consistent with

section 169A of the CAA, which gives

EPA broad authority to establish

regulations to ‘‘ensure reasonable

progress,’’ and with section 169B of the

CAA, which calls for EPA to establish

‘‘criteria for measuring reasonable

progress’’ toward the national goal.

This approach is designed to address

the concerns of those commenters

interested in greater State flexibility in

setting visibility goals, as well as the

concerns of those commenters who

believed that the presumptive 1

deciview target approach could actually

provide a disincentive for some States to

pursue more ambitious rates of progress,

particularly for the most impaired Class

I areas in the East. The EPA has taken

this approach in the final rule because

the CAA national visibility goal and

‘‘reasonable progress’’ provisions do not

mandate specific rates of progress, but

instead call for ‘‘reasonable progress’’

toward the ultimate goal of returning to

natural background conditions. Today’s

final rule requires the States to

determine the rate of progress for

remedying existing impairment that is

reasonable, taking into consideration the

statutory factors, and informed by input

from all stakeholders.

Required analysis of rate of progress

which would attain natural conditions

in sixty years. The EPA received

numerous comments expressing the

concern that a rate of progress that

would result in reaching the national

goal in 200 years should not be

considered ‘‘reasonable.’’ These

comments are based on the fact that the

most impaired Eastern United States

Class I areas have current conditions for

the worst days (around 26–31

deciviews) that exceed estimated

natural conditions (approximately 10–

12 deciviews) by 16–20 deciviews or

more. At the proposed presumptive rate

of progress of 1 deciview per 10 years,

it would take 200 years or more to reach

the national visibility goal in many

Eastern Class I areas. In addition,

several commenters felt that rates of

progress should vary between the east

and the west because many parts of the

western United States have much lower

levels of visibility impairment than the

east. For example, they asserted that a

1 deciview improvement over 10 years

may not be very ambitious in an eastern

location, whereas it could be very

ambitious in some of the least impaired

Class I areas in the west.

In order to address the diverse

concerns of commenters on the

proposal, EPA is establishing an

analytical requirement that takes into

account the varying levels of visibility

impairment in Class I areas around the

country while ensuring an equitable

approach nationwide. To determine an

equitable analytical approach, we

considered the CAA amendments of

1990, which require actions to attain air

quality health standards over a 20-year

period for the 1-hour ozone standard,

depending on the severity of the area’s

problem, and over a 10-year period for

new standards, such as the new 8-hour

ozone standard and the PM2.5 standards.

The CAA also requires reductions over

the same time period to address acid

rain. In the eastern United States, EPA’s

analyses show that the reductions from

these and other CAA programs will

result in a rate of improvement

estimated at approximately 3 deciviews

over the period from the mid-1990’s to

about 2005.82 The EPA calculated that if

this rate of improvement could be

sustained, these areas would reach the

national goal in 60 years.83 The EPA
35732 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

natural conditions, and multiplying 6 increments

by 10 years, assuming 10 years to achieve each

increment.

concluded that it would be reasonable

to establish an analytical requirement

based on this rate of progress given that

this rate of improvement is expected to

be achieved due to emissions under

CAA programs.

The EPA also believes that the

analytical requirement of the rate of

improvement needed to reach natural

conditions in 60 years is reasonable

because in the near-term, cost-effective

controls will continue to be available to

reduce emissions that contribute to

visibility impairment in Class I areas

across the country. Recent analyses for

other air quality programs show that

significant emissions can be achieved

through cost-effective control measures.

In addition, in the longer term, it can

be expected that continued progress in

visibility will be possible as industrial

facilities built in the latter half of the

20th century reach the end of their

‘‘useful lives’’ and are retired and/or

replaced by cleaner, more fuel-efficient

facilities. Significant improvements in

pollution prevention techniques,

emissions control technologies, and

renewable energy have been made over

the past 30 years, and continue to be

made. History strongly suggests that

further innovations in control

technologies are likely to continue in

future decades, leading to the ability of

new plants to meet lower emissions

rates.

In light of this analysis of progress

that could potentially be achieved, EPA

has established in section

51.308(d)(1)(i)(B) an analytical

requirement for setting reasonable

progress goals that should provide for

greater equity between goals set for the

more impaired Eastern United States

and the less impaired Western United

States. This analytical requirement has

the following four steps.

First, the State (or regional planning

group) must compare the baseline

visibility conditions in the years 2000–

2004 (in deciviews) for the most

impaired days with the natural

background conditions, for each

relevant Class I area. From this

comparison, the State must determine

the amount of progress needed to reach

natural background conditions in 60

years, that is, by the year 2064. For

example, if the baseline visibility is 30

deciviews, and the natural background

is 12 deciviews, then this step would

show the need for an 18 deciview

improvement between 2004 and 2064.

Second, the State must identify the

uniform rate of progress over the 60 year

period that would be needed to attain

natural background conditions by the

year 2064. For the example case noted

above, where 18 deciviews is the

amount for the 60-year period, this

would result in a uniform rate of

progress for each year of (18/60), or 0.3

deciviews for a year.

Third, the State must identify the

amount of progress that would result if

this uniform rate of progress were

achieved during the period of the first

regional haze implementation plan. For

example, if the first implementation

plan covers a 10-year period, then for

the above example, the State would

identify a 3 deciview amount of

progress over that time period.

Fourth, the State must identify and

analyze the emissions measures that

would be needed to achieve this amount

of progress during the period covered by

the first long-term strategy, and to

determine whether those measures are

reasonable based on the statutory

factors. These factors are the costs of

compliance with the measures, the time

necessary for compliance with the

measures, the energy and nonair quality

environmental impacts of the

compliance with the measures, and the

remaining useful life of any existing

source subject to the measures.

In doing this analysis, the State must

consult with other States which are

anticipated to contribute to visibility

impairment in the Class I area under

consideration. Because haze is a

regional problem, States are encouraged

to work together to develop acceptable

approaches for addressing visibility

problems to which they jointly

contribute. If a contributing State cannot

agree with the State establishing the

reasonable progress goal, the State

setting the goal must describe the

actions taken to resolve the

disagreement.

If the State determines that the

amount of progress identified through

the analysis is reasonable based upon

the statutory factors, the State should

identify this amount of progress as its

reasonable progress goal for the first

long-term strategy, unless it determines

that additional progress beyond this

amount is also reasonable. If the State

determines that additional progress is

reasonable based on the statutory

factors, the State should adopt that

amount of progress as its goal for the

first long-term strategy.

If the State determines, based on the

statutory factors, that the identified

uniform rate of progress needed to reach

natural conditions is not reasonable, the

State must provide in its plan

submission the analysis and rationale

supporting this determination. The State

then must provide a demonstration as

part of its SIP submission showing why

a less ambitious goal is reasonable,

based on the statutory factors. The EPA

intends to issue guidance interpreting

the statutory factors and providing

examples of ways in which they may be

applied.

The State must also provide to the

public, in accordance with section

51.308(d)(1)(ii), an assessment of the

number of years it would take to reach

natural conditions if the State continued

to make progress at the alternative rate

of progress it selected. For example, if

average worst day visibility at the class

I area is 18 deciviews from estimated

natural conditions, the uniform rate of

progress needed to reach natural

conditions is 3 deciviews per 10 years.

If the State determined that 3 deciviews

is not reasonable but 2 deciviews is,

then the State would have to include a

statement in its SIP that it would take

90 years to reach natural conditions if

this rate is maintained.

It should be noted that in developing

the first regional haze implementation

plan (and subsequent revisions), there is

a time period of several years between

the time period for which data are

available and the date of plan

submission. The first regional haze

implementation plans for most of the

United States will use the years 2000

through 2004 as the baseline for

monitoring and emission inventories,

while the first implementation plan for

much of the country will not be due

until a deadline that occurs between

2006 to 2008. In identifying the amount

of progress needed by the end of the

implementation period (the third step

described above), States must account

for this time period. Assume, for

example, for the case discussed above

(i.e., a 30 deciview baseline, and a

uniform rate of progress of 0.3

deciviews per year to reach natural

conditions in 60 years) that the first

regional haze SIPs covers the years 2009

through the year 2018. For this case,

there would thus be a 4-year period

(2005 through 2008) that would occur

between the baseline and the date of SIP

submission. The uniform rate of

progress of 0.3 deciviews per year over

this time period would result in 1.2

deciviews of improvement before the

plan submission. Hence, for this

example, in identifying the amount of

progress needed between the baseline

and the end of the implementation

period (i.e., the year 2018), the State

must evaluate strategies that provide for

a total of 4.2 deciviews: 1.2 deciviews

between the last year of the baseline

period and plan submission, and 3

deciviews for the implementation
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35733

84 Data from the IMPROVE network show that for

several sites in the Eastern United States, the

deciview values for the best days are greater than

14 deciviews, which is higher than even the

NAPAP estimate of annual average conditions in

the Eastern United States (9.6 deciviews).

period. The effect of this provision is

that States must be mindful of the

expected activities that take place before

plan submission. Generally, we expect

for the first plan submission period that

progress in visibility improvement will

continue to occur during the 2004 to

2008 period due to implementation of

other CAA programs.

Rationale for the required 60-year

analysis. The EPA has adopted this

analytical requirement for two reasons.

First, a common analytical framework

that recognizes regional differences

meets the concerns of several

commenters by providing greater equity

between the Eastern United States and

Western United States.

Second, EPA believes this analysis

will provide important additional

information for the public to consider as

States establish progress goals. The EPA

believes this analysis will provide for a

more informed and equitable decision

making process by giving the public

information about the level of emissions

needed, related costs, and other factors

associated with improvements in

visibility. The EPA recommends that as

part of this process, the States use

computer-based scene optics modeling

tools to present to the general public the

anticipated change in Class I area

visibility that would result from one

reasonable progress goal versus another.

Consideration of other CAA measures.

In determining the emissions and

visibility improvement achieved during

each implementation period, States

should include all air quality

improvements that will be achieved by

other programs and activities under the

CAA and any State air pollution control

requirements. Therefore, any reasonable

progress goal for a Class I area should

reflect at least the rate of visibility

improvement expected from the

implementation of other ‘‘applicable

requirements’’ under the CAA during

the period covered by the long-term

strategy. Consequently, States must take

into account, at a minimum, the effect

of measures to meet the NAAQS, the

national mobile source program, and

other applicable requirements under the

CAA on Class I area visibility.

While, as noted above, based on our

current understanding, EPA expects in

the eastern United States that the

reductions from measures implementing

the CAA requirements will provide the

visibility improvement and emissions

needed for reasonable progress during

the first regional haze implementation

plan, EPA also recognizes that States

will not be submitting their regional

haze plans for several years. In

developing its submittal, each State will

need to conduct analyses to support its

reasonable progress goals according to

information available at the time the

plan is submitted about benefits from

the existing CAA programs. Each State

should set its goal(s) taking into

consideration input from its

stakeholders and based on the statutory

factors described above. In addition, the

State must also conduct a BART

determination for each source subject to

BART as required in section 51.308(e) of

the rule and described in section III.H.

of the preamble. In considering whether

reasonable progress will continue to be

maintained, States will need to consider

during each new SIP revision cycle

whether additional control measures for

improving visibility may be needed to

make reasonable progress based on the

statutory factors.

Some commenters expressed concern

that the State would be subject to

sanctions or enforcement actions in the

event that a State fails to meet a

reasonable progress target. As noted

above, the reasonable progress goal is a

goal and not a mandatory standard

which must be achieved by a particular

date as is the case with the NAAQS.

Once a State has adopted a reasonable

progress goal and determined what

progress will be made toward that goal

over a 10-year period, the goal itself is

not enforceable. All that is

‘‘enforceable’’ is the set of control

measures which the State has adopted

to meet that goal. If the State’s strategies

have been implemented but the State

has not met its reasonable progress goal,

the State could either: (1) revise its

strategies in the SIP for the next longterm strategy period to meet its goal, or

(2) revise the reasonable progress goals

for the next implementation period. In

either case, the State would be required

to base its decisions on appropriate

analyses of the statutory factors

included in section 51.308(d)(1)(i)(A)

and (B) of the final rule.

If a State fails to submit an approvable

SIP, or if it fails to implement and

enforce strategies adopted into its SIP,

the State could be subject to sanctions

under the CAA. If the State continues to

fail in meeting its obligations, EPA

could be required to develop and

implement a Federal implementation

plan (FIP).

Allowing no degradation for the best

days. Some commenters supported the

goal of no degradation at a minimum,

but they asserted that in many Class I

areas, particularly in the east, the ‘‘best

days’’ are in fact still quite impaired. In

their view, a rule requiring only

preservation of existing clean days

would not meet the national goal.84

Other commenters stated that a ‘‘no

degradation’’ target for the clearest days

could result in limitations to economic

growth.

The final rule maintains the approach

used in the proposed rule, which

established a goal of no degradation for

the best visibility days. The EPA

believes this approach is consistent with

the national goal in that it is designed

to prevent future impairment, a

fundamental concept of section 169A of

the CAA. The EPA recognizes that the

best days are still impaired in many

Class I area locations, particularly in the

east. The EPA encourages States to

evaluate monitoring data to determine

whether the same types of sources are

affecting both the clear days and the

hazy days. If the relative contribution of

different particle types to light

extinction is similar for both clear and

hazy days, as it is for many sites

currently monitored, then by developing

strategies to improve conditions on the

worst visibility days, the States will

likely improve the entire distribution of

hazy and clear days. Thus, under the

final rule, the clean days for most Class

I areas are expected to improve over

time. Indeed, recent analyses of

visibility trends have shown that at

many Class I areas, deciview values for

the 20 percent least impaired days are

declining.

If at a Class I area the average

conditions for clear days degrades over

time, the State must provide in the next

plan revision an explanation of why this

happened, a set of measures designed to

reverse this trend, and a plan for

implementation during the next 10-year

period. The State should review the

effectiveness of these measures in

subsequent 5-year progress reviews.

Integral vistas. The scenic vistas

enjoyed by visitors to many parks often

extend to important natural features

outside these parks. The 1980 rules

included a provision whereby the States

could identify specific vistas for

protection. For this reason, EPA

solicited comment on whether the

integral vistas concept should be

extended to the regional haze program.

Some commenters supported

reopening the vista identification

program because such vistas are a

significant resource of a Class I area.

Several others opposed extending the

program for a variety of reasons.
35734 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

85The IMPROVE network is described in unit

III.I. of the preamble.

86 136 Cong. Rec. S2878 (daily ed. March 21,

1990) (statement of Sen. Adams).

87 GCVTC Report, p. x.

The final regional haze rule does not

extend the integral vista concept to the

regional haze program. As noted earlier

in the background section of this

preamble, regional haze is caused by a

multitude of sources across a broad

geographic area, and it can create a

uniform haze in all directions. The

regional haze program is designed to

bring about improvements in regional

visibility for the range of possible views

of sky and terrain found in any Class I

area. Accordingly, the program does not

protect only specific views from a Class

I area. To address haze, regional

strategies will be needed, and emissions

resulting from these strategies are

expected to improve visibility across a

broad region, not just within a Class I

area. Thus, although the regional haze

program does not include a specific

provision regarding integral vistas, the

long-term strategies developed to meet

reasonable progress goals would also

serve to improve scenic vistas viewed

from and within Class I areas.

Use of 20 percent most-impaired days

and 20 percent least-impaired days. The

final rule maintains the approach

discussed in the proposal of improving

the most-impaired visibility days (i.e.,

the average of the 20 percent most

impaired days over an entire year), and

allowing no degradation in the

‘‘cleanest’’ or least impaired days (i.e.,

the average of the 20 percent least

impaired days over an entire year). In

deciding upon an appropriate

characterization of the ‘‘most’’ and

‘‘least’’ impaired days, EPA considered

the typical frequency of aerosol

monitoring in the IMPROVE network 85

(once every 3 days), and the number of

samples that would be available for

analysis annually (122 possible samples

per year). The EPA believes that

calculating annual ‘‘best’’ and ‘‘worst’’

conditions on the basis of an average of

the 20 percent best and worst visibility

days represents a reasonable approach

to characterizing the typical best and

worst conditions without having these

values unduly influenced by a single

anomalous data point.

The EPA’s basis for maintaining the

proposed approach is supported by the

CAA and its legislative history, and by

the approach used by the GCVTC in its

technical assessment work and in its

definition of reasonable progress. The

EPA believes that a rule that requires

strategies for improving the worst days

and allowing no degradation on the

clean days is consistent with the

national visibility goal in section 169A

of the CAA, which calls for preventing

any future impairment (protecting

clearest days) and remedying any

existing impairment (improving the

already impaired days). This approach

is also supported by the legislative

history of the 1990 CAA and the

reasonable progress definition. The

legislative history provides that, ‘‘At a

minimum, progress and improvement

must require that visibility be

perceptibly improved compared to

periods of impairment, and that it not be

degraded or impaired during conditions

that historically contribute to relatively

unimpaired visibility.’’ 86 The GCVTC

interpreted ‘‘reasonable progress’’ to be

‘‘achieving continuous emissions

reductions necessary to reduce existing

impairment and attain a steady

improvement in visibility in mandatory

Class I areas, and managing emissions

growth so as to prevent perceptible

degradation of clear air days.’’ 87 In

today’s final rule, EPA is similarly

providing for ‘‘attaining a steady

improvement in visibility’’ and

‘‘preventing degradation of clean air

days’’ through the requirement to

improve the haziest days and prevent

degradation of the clearest days.

Tracking progress based on 5-year

averages. To determine whether

reasonable progress in improving

visibility is being achieved, States will

need to collect and analyze air quality

data each year and review progress at 5-

year intervals. Because the regional haze

program represents a long-term effort to

improve visibility in Class I areas, EPA

believes that monitoring and

assessments of progress should not be

unduly influenced by short-term events

or unusual meteorological conditions,

but should reflect trends in air quality

which are robust and insensitive to

minor fluctuations. For this reason, the

final rule calls for measuring progress

by tracking changes in 5-year average

deciview values for the haziest and

clearest days, and comparing these

current conditions against baseline

conditions as well as impairment levels

at the time of the last SIP revision. (See

unit III.E above for further discussion

about establishing baseline and current

conditions based on 5-year averages.)

G. Long-Term Strategy

Proposed rule. Under Section

169A(b)(2) of the CAA, EPA’s visibility

regulations must require States to

include in their SIPs ‘‘such emission

limitations schedules of compliance and

other measures as may be necessary to

make reasonable progress toward

meeting the national goal specified in

* * * [section 169A(a)] * * *’’ In

section 169A(b)(2)(B), the CAA requires

that these SIPs must include a ‘‘longterm (ten to fifteen years) strategy for

making reasonable progress toward

meeting the national goal.’’ The EPA

interprets the term ‘‘long-term strategy’’

as the control measures that are needed

to ensure reasonable progress, together

with a demonstration that those

measures will provide for reasonable

progress during the 10 to 15 year period.

The proposed rule required the State to

develop a long-term strategy for regional

haze with the initial regional haze SIP,

and to provide for regular updates.

(Issues regarding updates of the longterm strategy are discussed below in

unit III.J).

The proposal also required States to

consider a specific list of factors when

they developed their long-term

strategies for regional haze. Under the

proposal, in developing long-term

strategies for regional haze, States

would be required to consider the six

items listed in section 51.306(e) of the

1980 rule, and the five items listed in

section 51.306(g) of the 1980 rule. We

proposed to add a seventh item to

section 51.306(e), ‘‘the anticipated effect

on visibility due to projected changes in

point, area and mobile source emissions

over the next 10 years.’’

Comments received. Public

commenters on the long-term strategy

requirement expressed concerns that the

proposed rule had over-emphasized

stationary source contributions, and had

under-emphasized contributions from

minor sources, area sources, mobile

sources and prescribed fires. Other

commenters expressed concerns that

control strategies would be ineffective

in cases where contributions from

international sources were causing

visibility impairment. Commenters also

emphasized that States be able to take

credit in their long-term strategies for

the effects of existing CAA programs.

We did not receive any comments on

the specific list of factors to consider in

developing long-term strategies.

Final rule. As discussed further below

in unit III.J of today’s notice, the final

rule requires control strategies to cover

an initial implementation period

extending to the year 2018, with a

reassessment and revision of those

strategies, as appropriate, every 10

years. The final rule, in section

51.308(d)(3), includes a requirement for

regional haze SIPs to include a longterm strategy. The long-term strategy

must include specific enforceable

measures that are sufficient to meet the

‘‘reasonable progress goals’’ for all Class
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35735

I areas affected by emissions from the

State.

Multistate contributions—

requirements for consultation and

apportionment. As noted in section

51.308(d)(3)(i), when a State’s emissions

are reasonably anticipated to cause or

contribute to impairment in a Class I

area located in another State or States,

the rule requires that the State consult

with the other State or States in order

to develop coordinated emission

management strategies. Regarding the

Class I areas within the State, section

51.308(d)(3)(i) also requires States to

consult with any other State having

emissions that are reasonably

anticipated to contribute to impairment

in any Class I area within the State.

For Class I areas where the State and

other States cause or contribute to

impairment in a mandatory Class I area,

section 51.308(d)(3)(ii) requires that the

State must demonstrate that it has

included in its implementation plan all

measures necessary to obtain its share of

the emissions needed to meet the

progress goal for the area. Section

51.308(d)(3)(iii) requires that States

must document the technical basis,

including modeling, monitoring and

emissions information, that it uses to

determine its apportionment of

emission reduction obligations for the

Class I areas the State affects. It is

important that EPA and stakeholders

understand the modeling, monitoring

and emission information that the State

used to support its conclusion that the

long-term strategy provides for

reasonable progress.

The EPA expects that much of the

consultation, apportionment

demonstrations, and technical

documentation will be facilitated and

developed by regional planning

organizations. We expect, and

encourage, these efforts to develop a

common technical basis and

apportionment for long-term strategies

that could be approved by individual

State participants, and translated into

regional haze SIPs for submission to

EPA. While States are not bound by the

results of a regional planning effort, nor

can the content of their SIPs be dictated

by a regional planning body, we expect

that a coordinated regional effort will

likely produce results the States will

find beneficial in developing their

regional haze implementation plans.

Any State choosing not to follow the

recommendations of a regional body

would need to provide a specific

technical basis that its strategy

nonetheless provides for reasonable

progress based on the statutory factors.

At the same time, EPA cannot require

States to participate in regional

planning efforts if the State prefers to

develop a long-term strategy on its own.

We note that any State that acts alone

in this regard must conduct the

necessary technical support to justify

their apportionment, which generally

will require regional inventories and a

regional modeling analysis.

Additionally, any such State must

consult with other States before

submitting its long-term strategy to EPA.

Consideration of all anthropogenic

sources. In the final rule, we have

clarified in section 51.308(d)(3)(iv) that

the State should consider all types of

anthropogenic sources including

stationary, minor, mobile, and area

sources in developing its long-term

strategy. The State should review all

such sources in identifying the emission

reduction measures to be included in

the strategy. In addition, we provide the

following points of clarification:

Minor sources. Because of the focus of

the BART provision on major stationary

sources, EPA believes that commenters

may have the impression that EPA has

concluded that minor sources with

emissions, below the BART cutoff of

250 tons per year, are not significant

contributors to regional haze. This is not

the case. The EPA believes that States

should take the cumulative emissions

from minor sources into account in

developing their regional haze long-term

strategies. For example, if growth in

minor source emissions for a particular

category had a substantial impact on

emission trends and a corresponding

effect on regional haze in a given

geographic area, States should consider

emission control strategies for such

source categories as part of their longterm strategies.

Mobile sources. In cases where

pollutants emitted by mobile sources

contribute to regional haze, States must

include in their SIPs mobile source

emissions inventories representing

current conditions, as well as

comparisons of those emissions with

future emissions projected for the end of

the covered by the long-term strategy. It

will be particularly important for States

to address the effects of population

growth and accompanying increases in

vehicle miles traveled on their ability to

provide for reasonable progress. The

EPA agrees with commenters that

national mobile source emission

standards also will be an important

factor in projecting mobile source

emissions. The EPA intends to support

States in their efforts to estimate mobile

source emissions (including the effects

of Federal rules) of pollutants that lead

to regional haze.

Area sources. States also need to

develop emission inventories and

conduct analyses to understand the

importance of area sources. For

example, the GCVTC report cited

emissions from road dust as a possible

contributor to impairment. Depending

on the nature of the visibility problem,

road dust and other area sources may at

times make a significant contribution to

visibility impairment. States should

include area sources in emission

inventories and control strategy

analyses as warranted.

Fire. Commenters expressed a number

of concerns with respect to the

appropriate consideration of emissions

from fire in the development of longterm strategies.

The EPA notes that fire emissions

have both a natural and a manmade

component. In addressing fire emissions

in long-term strategies, EPA believes

that States must take into account the

degree to which fire emissions cause or

contribute to ‘‘manmade’’ visibility

impairment and its contribution to

natural background conditions.

Reducing ‘‘manmade’’ visibility

impairment is the focus of sections

169A and 169B of the CAA. The EPA

recognizes the natural role of fire in

forest ecosystems, and the fact that

forest fuels have built up over many

years due to past management practices

designed to protect public health and

safety through fire suppression.

Research has shown that these practices

have led to an increased risk of

catastrophic wildfire as well as reduced

forest health. In response to this

situation, the Federal land management

agencies, as well as some States and

private landowners, have recommended

the increased use of prescribed fire in

order to return certain forest ecosystems

to a more natural fire cycle and to

reduce the risk of adverse health and

environmental impacts due to

catastrophic wildfire.

The EPA also recognizes that fire of

all kinds (wildfire, prescribed fire, etc.)

contributes to regional haze, and that

there is a complex relationship between

what is considered a natural source of

fire versus a human-caused source of

fire. For example, the increased use of

prescribed fire in some ecosystems may

lead to PM emissions levels lower than

those that would be expected from

catastrophic wildfire. Given that the

purpose of prescribed fire in many

instances is to restore natural fire cycles

to forest ecosystems, it would be

appropriate to consider some portion of

prescribed fire as ‘‘natural.’’

Consequently, in determining natural

background for a Class I area, EPA

believes States should be permitted to

consider some amount of fire in the

calculation to reflect the fact that some
35736 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

prescribed fire effects serve merely to

offset what would be expected to occur

naturally. The EPA will work with the

FLMs, States and other stakeholders to

develop guidance on ways in which fire

can be considered in the determination

of natural background, and in the

determination baseline and current

conditions.

Commenters asserted that in the

proposed rule, EPA ignored the

contribution of fires and thus

overlooked the most important hazecontributing emission source in many

Class I areas. The EPA agrees that fire

is an important emission source to

include in the analysis, but current data

do not show that fire is the predominant

source of visibility impairment in any

Class I area. Annual data from the

IMPROVE network show that elemental

carbon (which we generally use as the

main indicator of emissions from fire

and other combustion sources such as

diesel emissions), accounts for only

about 3–7 percent of PM2.5 mass on the

worst visibility days in eastern sites. In

western sites, elemental carbon

accounts for about 4–7 percent of total

PM2.5 mass on the worst days. The

contribution from fires can be

substantial over short-term periods, but

fires occur relatively infrequently and

thus have a lower contribution to longterm averages. Fire events making

substantial contributions to haze in a

given Class I area have occurred

relatively infrequently, and as a

practical matter will contribute less than

sources for which emissions are more

continuous. As noted previously, the

final rule requires States to develop

long-term strategies for regional haze

that address 5-year averages of the 20

percent worst days. These 5-year

averages will also be used in evaluating

monitoring results. The frequency with

which fires occur will effect the

importance of their emissions on

predicted future 5-year averages for

visibility conditions on the 20 percent

worst days.

Commenters expressed concerns with

the expected increase in emissions from

prescribed burning on Federal lands.

Specifically, the commenters asserted

that States would not be able to address

emission increases from these

prescribed burns, and that stationary

sources would be required to

compensate for the increased amount.

The EPA believes these commenters

are mistaken in their view of State’s

authority to address emissions from

prescribed Federal burns. Pursuant to

section 118 of the CAA, when States

impose requirements on sources,

Federal agencies must comply with

those requirements in the same manner,

and to the same extent, as any

nongovernmental entity. States therefore

have the authority to address emissions

from prescribed Federal burns in the

same manner, and to the same extent,

they regulate prescribed fires generally.

Additionally, to the degree that States

determine in the development of longrange strategies that the manmade

component of fire is a significant

contributor to regional haze, States have

a substantial degree of flexibility under

the CAA and in the final rule. The final

rule provides States flexibility in

determining the amount of progress that

is ‘‘reasonable’’ in light of the statutory

factors, and also provides flexibility to

determine the best mix of strategies to

meet the reasonable progress goal they

select. Nothing in the final rule requires

States to develop long-term strategies

that reduce emissions from other

sources by amounts equivalent to any

increases from the manmade fraction of

prescribed fires. We do expect that

States consider and analyze the full

range of available control measures and

that they consider the causes of

visibility impairment when evaluating

the potential measures to include in

their long-term strategies.

The EPA encourages the development

of smoke management programs

between air regulators and land

managers as a means to manage the

impacts of wildland and prescribed

burning. The sources of information

described above, as well as other

developmental efforts currently

underway, provide effective, flexible

approaches to smoke management.

Where smoke impacts from fire are

identified as an important contributor to

regional haze, smoke management

programs should be a key component of

regional and State regional haze

planning efforts and long-term

strategies.

There are a number of sources of

information on mitigation approaches

for fire emissions, including: (1) The

EPA Interim Air Quality Policy on

Wildland and Prescribed Burning, (2)

fire-related strategies developed by the

GCVTC and (3) the best available

control methods (BACM) document for

prescribed burning. In the Interim Air

Quality Policy on Wildland and

Prescribed Burning, EPA, in

collaboration with a national

stakeholder group comprised of Federal,

State, and private land managers, State

air regulators, environmental groups,

tribes, and others, developed a

framework for managing the impacts of

smoke from increased prescribed fire

programs across the country. This

policy describes the elements and

process of smoke management planning

that air regulators and land managers

can use to reach agreement on

development of smoke programs. The

GCVTC included a number of long-term

strategies for fire in its report and

recommendations, including emissions

tracking and emission goals for fire,

smoke management programs, and full

consideration for alternatives to fire.

The GCVTC’s strategy is illustrative of

the available mitigation approaches for

emissions from fire that other States

may consider. The GCVTC’s approach is

contained in section 51.309(d)(6) of the

final rule and discussed further in unit

IV.C of this notice. The BACM

document, Prescribed Burning

Background Document and Technical

Information Document, EPA–450/2–92–

003, is organized to discuss various

aspects of State smoke management

programs. The document includes

information on how States administer

and enforce programs for burn/no-burn

days, and information on various topics

including emission inventories, cost

estimation, and public information

programs.

Transboundary emissions from

sources outside the United States. Some

Class I areas located near international

borders are particularly prone to

influence by emissions beyond the

United States border. Commenters

expressed concerns that EPA should

take into account that States are not able

to control international sources in

reviewing a State’s proposal for a

reasonable progress target. Additionally,

commenters urged EPA to work with

Mexico and Canada to reduce emissions

from sources that States determine to be

significant contributors to regional haze

in their Class I areas.

The EPA agrees that the projected

emissions from international sources

will in some cases affect the ability of

States to meet reasonable progress goals.

The EPA does not expect States to

restrict emissions from domestic sources

to offset the impacts of international

transport of pollution. We believe that

States should evaluate the impacts of

current and projected emissions from

international sources in their regional

haze programs, particularly in cases

where it has already been well

documented that such sources are

important. At the same time, EPA will

work with the governments of Canada

and Mexico to seek cooperative

solutions on transboundary pollution

problems.

Factors to consider for long-term

strategies. In section 51.308(d)(3)(v) (A)

through (G) in the final rule, we have

incorporated a list of seven factors that

States must consider in developing

long-term strategies. The final rule
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35737

88H.R. Rep. No. 564, 95th Cong., 1st Sess. at 155

(1977) (emphasis added).

89See CAA sections 169A (b)(2)(A) & (g)(7).

includes six factors in the July 1997

proposal that are derived from section

51.306(e) of the existing rule, and the

additional item, ‘‘the anticipated net

effect on visibility due to projected

changes in point, area, and mobile

source emissions over the period

addressed by the long-term strategy’’

that was specifically added by the July

1997 proposal. We have decided not to

include the five proposed items that are

derived from section 51.306(g), because

four of these items are included on the

list of ‘‘reasonable progress’’ factors in

section 51.308(d)(1)(i)(A) of the final

rule, and because we believe that the

fifth factor ‘‘effect of new sources’’ is

part of ‘‘projected changes in point

source emissions.’’

In their regional haze SIP

submissions, States must describe how

each of these seven factors is taken into

account in developing long-term

strategies. We believe it is useful to

clarify several of these factors, and

EPA’s expectations on how SIPs can

address them.

Item (A): Emissions due to ongoing air

pollution control programs, including

measures to address reasonably

attributable visibility impairment.

It is expected that for some areas of

the country, such as parts of the eastern

United States, emissions achieved for

the acid rain program and for meeting

the PM2.5 NAAQS, will lead to

substantial improvements in visibility

as well. Item (A) makes clear that States

must take these other emissions into

account in developing their long-term

strategies for regional haze. We expect

that some States may be able to

demonstrate reasonable progress based

on these emissions alone, particularly

for the first 10-year period.

Item (B): Measures to mitigate the

impacts of construction activities.

Item (B) requires that in developing

long-term strategies, States must

consider the impacts of construction

activities. States, for example, should

include these activities in emission

inventories used for long-term strategy

development.

Item (C): Additional measures and

limitations and schedules for

compliance to achieve the reasonable

progress goal.

Where emissions from ongoing

requirements, addressed by item (A), are

not sufficient to achieve the reasonable

progress goal, States must identify

additional measures that will ensure

that the goal will be met. Schedules for

compliance for these additional

measures must be included in the SIP,

and measures considered for inclusion

must be identified in the SIP

submission.

Item (D): Source retirement and

replacement schedules.

Item (D) requires the consideration of

source retirement and replacement

schedules in developing the long-term

strategies, particularly, where these

schedules would have a significant

impact on regional emission loadings

and on a State’s ability to achieve

reasonable progress.

Item (E): Smoke management

techniques for agricultural and forestry

management purposes including plans

as they currently exist within the State

for these purposes.

Item (E) highlights the widely

recognized importance of prescribed

burning programs on regional haze.

Issues related to fire and forestry

management practices are discussed

above.

Item (F): Enforceability of emissions

limitations and control measures.

States must ensure that control

measures are written in a way that EPA

and citizens may enforce as a practical

matter. Guidance on practical

enforceability issues is readily available

in EPA policy guidance memoranda, for

example Guidance on Limiting Potential

to Emit in New Source Permitting, June

13, 1989.

Item (G): The anticipated net effect on

visibility due to projected changes in

point, area, and mobile source

emissions over the next 10 years.

Item (G) requires that States must

address the anticipated net effect on

visibility due to projected changes in

point, area, and mobile source

emissions over the next 10 years when

developing emissions strategies that will

meet the reasonable progress

requirements. In some areas, these

changes in emissions would be expected

primarily from population growth,

while in others, emissions changes may

result from potential new industrial,

energy, natural resource development,

or land management activities. These

changes in emissions would also

include the changes due to measures

developed specifically for the regional

haze program.

Relationship to long-term strategies

under the existing rule. The final rule

provides for coordination of the longterm strategies to address regional haze

impairment with any existing long-term

strategies under the 1980 visibility rule.

Some long-term strategies are already in

place to address reasonably attributable

visibility impairment under the existing

1980 regulation. Coordination of the two

programs is addressed in section

51.306(c) of the final rule. This section

clarifies two points. First, that the

provisions of existing long-term

strategies will continue to apply until

regional haze strategies are in place.

Second, once the first regional haze

strategy is in place, the final rule, in

section 51.306(c) requires the State to

develop a coordinated long-term

strategy which address both reasonably

attributable impairment and regional

haze.

H. Best Available Retrofit Technology

(BART)

Background. One of the principal

elements of the visibility protection

provisions of the CAA is the provision

in section 169A addressing the

installation of BART for certain existing

sources. The conference committee

report accompanying the 1977 CAA

amendments indicates that a major

concern motivating the adoption of the

visibility provisions was ‘‘the need to

remedy existing pollution in the Federal

mandatory class I areas from existing

sources.’’ 88 The BART provision in

section 169A(b)(2)(A) demonstrates

Congress’ intention to focus attention

directly on the problem of pollution

from a specific set of existing sources.

This provision provides that EPA’s

regulations to protect visibility must

require States to revise their SIPs to

contain such measures as may be

necessary to make reasonable progress

toward the national visibility goal,

including a requirement that certain

existing stationary sources procure,

install, and operate the ‘‘best available

retrofit technology.’’

The CAA defines the sources

potentially subject to BART as major

stationary sources, including

reconstructed sources, from one of 26

identified source categories which have

the potential to emit 250 tons per year

or more of any air pollutant, and which

were placed into operation between

August 1962 and August 1977.89 This

set of sources potentially subject to

BART was defined in the 1977 CAA and

will not be modified by rule. The 26

source categories are:

(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,
35738 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

90Section 51.301(c).

91 Id.

92See EPA, Office of Air Quality Planning and

Standards, Guidelines for Determining Best

Available Retrofit Technology for Coal-Fired Power

Plants and Other Existing Stationary Facilities,

EPA–450/3–80–009b, November 1980.

(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, and

(26) Charcoal production facilities.

In section 51.301(e) of the 1980

visibility regulations, a source meeting

the above criteria was defined as an

‘‘existing stationary facility.’’ In today’s

regional haze rule, EPA has added the

definition of a ‘‘BART-eligible source’’

in section 51.301(hh) that is identical to

the definition of ‘‘existing stationary

facility.’’ This new definition is used

throughout the regional haze rule and

preamble in order to avoid the potential

misinterpretation of the ‘‘existing

stationary facility’’ definition as

representing a collection of sources

broader than the subset of sources

potentially subject to BART.

The regulations issued in 1980 define

BART as ‘‘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 facility.90

The BART emission limitation must be

established, on a case-by-case basis,

taking into consideration the following

factors:

• The technology available,

• The costs of compliance,

• The energy and nonair

environmental impacts of compliance,

• Any pollution control equipment in

use at the source,

• The remaining useful life of the

source, and

• The degree of improvement in

visibility which may reasonably be

anticipated from the use of such

technology.91

The EPA published guidelines in 1980

which outline the general procedures

for States to follow in analyzing sources

and establishing BART emission

limits.92 These guidelines apply to

situations in which visibility

impairment in the Class I area is

determined to be ‘‘reasonably

attributable’’ to a single source or a

small group of sources.

Proposed rule. The proposed regional

haze rule discussed a process for

addressing BART in the context of

regional haze and requested comment

on how the requirement should be

implemented. The first step in this

process was a requirement that the State

identify all sources potentially subject

to BART early in the planning process.

The second step required the State to

submit a plan and schedule for

evaluating BART and the corresponding

potential emissions for those existing

sources which may reasonably be

anticipated to contribute to regional

haze visibility impairment. The notice

proposed to provide 3 years for

completing this evaluation so that the

results could be taken into

consideration by States as they develop

coordinated strategies for attaining the

PM2.5 and ozone NAAQS.

In setting out the proposed approach

to the BART requirement, EPA proposed

that the test for determining whether a

BART-eligible source ‘‘may reasonably

be anticipated to contribute’’ to regional

haze should be evaluated in the context

of the overall emissions reduction

strategy. The EPA also noted that it

believed that a similar approach should

be taken in addressing ‘‘the degree of

improvement in visibility which may

reasonably be anticipated’’ from the

imposition of BART controls. The EPA

proposed a cumulative approach

because of the nature of the regional

haze problem (i.e., the cumulative

product of emissions from many sources

over a broad area) and because of the

time and expense necessary to try to

determine, one source at a time, the

percentage contribution of each BARTeligible source to regional haze. In

addition, EPA noted the substantial

technical difficulties associated with

estimating the degree of visibility

improvement resulting from a single

source. The EPA broadly requested

comments on effective approaches for

States and sources to meet the BART

requirement under the regional haze

program in the most appropriate

manner, and in particular how BART,

once determined, should be

implemented.

Comments received. Commenters

identified a number of issues

concerning how EPA should address the

BART requirement under the regional

haze program. Some commenters

asserted that the BART requirement

simply should not apply under the

regional haze program. These

commenters argued that the

procurement, installation, and operation

of BART is not explicitly required under

section 169B, and that section 169B is

the primary statutory authority for the

regional haze program. Other opponents

of the BART requirement contended

that the proposal placed too much

emphasis on stationary sources, and on

BART sources in particular, as opposed

to other sources of visibility-impairing

pollutant emissions, such as mobile and

area sources. The commenters

contended that BART should not be the

principal control strategy employed

under the regional haze program.

Another group of commenters

supported EPA’s proposed approach for

addressing the BART requirement.

Some pointed out that while existing

stationary sources are not the only

contributors to regional haze,

controlling these sources is an essential

element of a national regional haze

program. These commenters also

supported the approach of evaluating

BART-eligible sources collectively to

determine their overall contribution to

visibility impairment within a given

airshed. Several commenters

recommended that BART be equivalent

to, or more stringent than, new source

performance standards (NSPS) for sulfur

dioxide and nitrogen oxides. Some

commenters suggested allowing an

emissions cap-and-trade program to

meet the BART requirement. One

commenter described a process whereby

States would conduct an assessment of

the availability of retrofit controls for all

BART-eligible sources in a region,

calculate the cumulative emissions

possible from application of BART to

eligible sources, establish a cap for each

visibility-reducing pollutant, and

implement a 10-year program to achieve

emissions equivalent to the emissions

cap.

Response to comments. The EPA

disagrees with the commenters who

argued that the BART requirements

should not apply to the regional haze

program. The statutory authority for

developing a regional haze program

emanates from section 169A of the CAA,

and any SIPs that are to be developed

under a regional haze program must

include provisions that meet the

requirements of this section, including

the requirement that certain sources

procure, install, and operate BART.
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35739

93See CAA section 169A(g)(6); see also Maine v.

Thomas, 874 F.2d.883, 885 (1st Cir. 1989) (‘‘EPA’s

mandate to control the vexing problem of regional

haze emanates directly’’ from CAA section 169A).

94H.R. Rep. No. 294, 95th Cong., 1st Sess. 204

(1977).

95 45 FR 80084 (Dec. 2, 1980).

96See 136 Cong. Rec. S2878 (daily ed. March 21,

1990) (statement of Sen. Adams) (‘‘[t]he authority to

establish visibility transport regions and

commissions is a supplement to the administrators

[sic] obligation under current law. * * * The

Administrator may not delay requirements under

section 169A because of the appointment of a

commission for a region under section 169B’’)

(daily ed. Oct. 26, 1990) (statement of Rep. Wyden)

(‘‘[n]either the original House language nor the

Senate language adopted in conference repealed or

lessened EPA’s obligations under the 1977 law’’).

97 See Central Arizona Water Conservation

District v. EPA, 990 F.2d 1531, 1543 (1993).

98See 56 FR at 50178.

99Central Arizona Water Conservation District v.

EPA, 990 F.2d 1531, 1543 (1993).

Since 1977, section 169A of the CAA

has authorized EPA to address regional

haze. Section 169A(a)(1) of the CAA

establishes as the national visibility

protection goal ‘‘the prevention of any

future, and the remedying of any

existing, impairment of visibility in

Class I areas which impairment results

from manmade air pollution.’’ Visibility

impairment is defined broadly in the

CAA and includes that caused by

regional haze.93 This language does not

distinguish between reasonably

attributable impairment and regional

haze, but provides for visibility

protection generally. This reading of the

statute is consistent with the legislative

history; in adopting section 169A,

Congress evinced its intent to address

impairment caused by ‘‘hazes’’ and the

potential corresponding need to control

a ‘‘variety of sources’’ and ‘‘regionally

distributed sources.’’ 94 While EPA

deferred addressing regional haze in

1980 when it promulgated the first

phase of visibility regulations, it did so

because of technical obstacles, not

because of a limitation on its legal

authority.95 Indeed, in the 1980 rule,

EPA expressed its intent to address

regional haze in a future rulemaking

under section 169A. Thus, EPA’s

decision to address visibility

impairment in separate phases does not

change the fact that the BART

requirement is an integral part of the

statutory scheme in section 169A.

The provisions in section 169B of the

CAA, adopted in 1990, do not override

EPA’s statutory authority to require

State plans to remedy regional haze.

These provisions grew out of Congress’

frustration that EPA had not more

expeditiously addressed regional haze

under its section 169A delegated

rulemaking authority. Thus, section

169B(e) explicitly requires EPA to carry

out its ‘‘regulatory responsibilities

under section [169A]’’ within a set time

period. The legislative history confirms

that Congress did not intend section

169B to impinge upon EPA’s longstanding authority to address regional

haze visibility impairment,96 including

the authority to require BART.

The EPA believes that commenters

asserting that EPA overemphasized the

control of stationary sources and, in

particular, the role of BART in the

regional haze program misinterpreted

the proposal. The EPA did not intend to

emphasize controls on BART-eligible

sources over, or to the exclusion of,

other sources. While the BART

requirement is limited to a specified

population of major stationary sources,

States will need to consider measures

addressing a wide range of sources and

activities, including mobile sources,

area sources, activities involving fire,

and other major and non-major

stationary point sources in their longterm strategies. The unit on long-term

strategies includes further discussion of

this point.

Final Rule. The final rule requires

each implementation plan to be revised

to contain two basic elements related to

BART. The first is the requirement that

the States submit a list of the ‘‘BARTeligible sources’’ in the State. Second,

the State must determine and include in

the plan the ‘‘best available retrofit

technology,’’ taking into account certain

factors identified in section 169A(g)(2)

of the CAA, for each BART-eligible

source in the State reasonably

anticipated to cause or contribute to any

impairment of visibility.

In recognition of the control and cost

efficiencies that can be achieved

through trading programs and other

alternative measures, EPA is providing

States with the opportunity to adopt

alternative measures in lieu of BART

where such measures would achieve

even greater reasonable progress toward

the national visibility goal. The

overarching requirement of the visibility

protection provisions of section 169A is

to make reasonable progress toward the

national goal of eliminating visibility

impairment. If greater reasonable

progress can be made through an

approach that does not require source

specific application of BART, EPA

believes that approach would comport

with this statutory goal. The EPA

reached this conclusion in determining

the appropriate measures to address

visibility impairment in the Grand

Canyon National Park resulting from the

Navajo Generating Station.97 In that

case, EPA ultimately chose not to adopt

the emission control limits indicated by

its BART analysis.98 Instead, as

explained by the Ninth Circuit in

upholding EPA’s final decision, EPA

acted within its discretion in adopting

an alternative emission control standard

‘‘that would produce greater visibility

improvement at a lower cost. Congress’s

use of the term ‘including’ in [section

169A(b)(2)] prior to its listing BART as

a method of attaining ‘reasonable

progress’ supports EPA’s position that it

has the discretion to allow States to

adopt implementation plan provisions

other than those provided by sourcespecific BART analyses in situations

where the agency reasonably concludes

that more ‘reasonable progress’ will

thereby be attained.’’ 99 Under today’s

final rule, States may elect to adopt an

emissions trading program or other

alternative measures in lieu of BART so

long as greater reasonable progress is

made.

List of BART-eligible sources. To

ensure adequate time for developing

long-term strategies to ensure reasonable

progress, we recommend that States

begin identifying and evaluating the list

of potential BART sources as soon as

possible after promulgation of the final

rule. Identifying the BART-eligible

sources will require States to collect

information as to the dates that emission

units at stationary sources were placed

into operation, the pollutants emitted,

and the potential to emit of these units.

We suggest that, at the same time that

they begin refining their emissions

inventories for PM2.5 and its precursors,

States request that stationary sources

provide them with these dates. While

such information is generally available

for electric utilities through data bases

maintained by the Energy Information

Administration, this information is not

normally maintained in national data

bases for the other 25 source categories

subject to BART. However, EPA believes

that much of this information is likely

to be available in States permitting data

bases or other inventories. To assist the

States in this task, we will continue

efforts to identify other helpful sources

of information.

Determination of sources subject to

BART. After the State has identified the

BART-eligible sources, the next step is

determining whether these sources emit

any air pollutant ‘‘which may

reasonably be anticipated to cause or

contribute’’ to any visibility impairment

in a Federal Class I area. As noted in the

proposal, EPA believes that this

determination should not require

extremely costly or lengthy studies of

the contribution of specific sources to

regional haze. Unlike the 1980

regulatory program, which addresses the
35740 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

100Central Arizona Water Conservaiton District v.

EPA, 990 F.2d 1531, 1541 (9th Cir. 1993).

101 63 FR 57356, 57376 (Oct. 27, 1998).

102See 40 CFR part 51, appendix W for

information on EPA’s modeling guideline for

conducting regional-scale modeling for particulate

matter and visibility.

103See section 51.301(c).

104See CAA section 169A(g)(2).

105Ellerman A. Danny et al., Emissions Trading

Under the U.S. Acid Rain Program: Evaluation of

Compliance Costs and Allowance Market

Performance, Massachusetts Institute of

Technology, Center for Energy and Environmental

Policy Research, 1997.

visibility impairment that is reasonably

attributable to a specific source or small

group of sources, today’s final rule

addresses the problem of visibility

impairment resulting from emissions

from a multitude of sources located

across a wide geographic area. As the

regional haze rule is not limited to

addressing visibility impairment that

can be attributed to a specific source or

small group of sources, EPA believes it

would be inappropriate to focus on the

contribution of one source or a small

group of sources. First, the States will

not face the same need to define the

precise contribution from one particular

source to the visibility problem. Second,

establishing the contribution from one

particular source to the problem of

regional haze would require lengthy and

expensive studies and pose substantial

technical difficulties. The EPA has thus

concluded that a detailed sourcereceptor analysis would not be

appropriate in determining whether a

source ‘‘may reasonably be anticipated

to contribute’’ to regional haze in a Class

I area.

In implementing today’s final rule, a

State should find that a BART-eligible

source is ‘‘reasonably anticipated to

cause or contribute’’ to regional haze if

it can be shown that the source emits

pollutants within a geographic area from

which pollutants can be emitted and

transported downwind to a Class I area.

The EPA believes that this test is an

appropriate one for determining

whether a source can reasonably be

anticipated to cause or contribute to the

problem of regional haze. As the Ninth

Circuit stated in considering this

language:

Congress mandated an extremely low

triggering threshold, requiring the

installment of stringent emission controls

when an individual source ‘‘emits any air

pollutant which may reasonably be

anticipated to cause or contribute to any

impairment of visibility’’ in a Class I Federal

area. 42 U.S.C. sec. 7491(b)(2)(A). The NAS

correctly noted that Congress has not

required ironclad scientific certainty in

establishing the precise relationship between

a source’s emission and resulting visibility

impairment.* * * 100

The approach taken here is consistent

with that taken in the programs for acid

rain and ozone, programs which also

address regional air quality problems

caused by transported pollutants. These

programs do not require a specific

demonstration of each source’s

contribution to the overall problem, but

instead focus efforts on developing costeffective solutions to reducing

emissions over a broad area that is

regional or national in scope. For

example, in the recent NOX SIP call

addressing the regional transport of NOX

emissions (an ozone precursor) in the

Eastern United States, EPA adopted a

‘‘collective contribution’’ approach to

determining whether sources

‘‘contribute’’ to ozone nonattainment in

downwind areas. In this rulemaking,

EPA concluded that because ozone

nonattainment results from the

collective contribution of many entities

over a broad geographic area, even

relatively small (in an absolute sense)

contributions from upwind entities

should be considered to be

‘‘significant.’’ 101

The EPA has concluded that a similar

approach in the regional haze program

is appropriate. Where emissions from a

region are considered to contribute to

regional haze in a Class I area, any

emissions from BART-eligible sources

in that region should also be considered

to cause or contribute to the regional

haze problem. The EPA will issue and

update guidance, including EPA

modeling guidelines,102 to assist the

States in analyzing whether sources

contribute to regional haze.

Establishing source-specific BART

emission limits. The second element of

the BART requirement is for the States

to establish emission limitations for

those BART-eligible sources which may

reasonably be anticipated to cause or

contribute to regional haze. To meet this

requirement, the State must develop

source-specific emission limits which

reflect the application of the best system

of continuous emission reduction for

each pollutant which is emitted by a

source subject to BART.103 As stated

above, the State can also choose to

develop an emissions trading program,

or other alternative measure, that

achieve greater reasonable progress

rather than require source specific

BART emission limits on each source

subject to BART.

In developing source specific

emission limits for BART, the State

must take into consideration the

technology available and a number of

specific factors set forth in the statute.

These factors are the costs of

compliance, the energy and nonair

environmental impacts of compliance,

any existing pollution control

technology in use at the source, the

remaining useful life of the source, and

the degree of improvement in visibility

which may reasonably be anticipated

from the use of such technology. Taking

these factors into account, the State may

conclude that BART is the best level of

emissions reduction that can be

achieved by available retrofit technology

or some other level of control. In some

cases, the State may determine that a

source has already installed sufficiently

stringent emission controls for

compliance with other programs (e.g.,

the acid rain program), such that no

additional controls would be needed for

compliance with the BART requirement.

In establishing BART for a particular

facility, the State must make available

during public review of the SIP at the

State level the materials supporting its

BART determination. The State must

also include this documentation in the

technical support materials

accompanying the SIP.

In establishing source specific BART

emission limits, the State should

identify the maximum level of emission

reduction that has been achieved in

other recent retrofits at existing sources

in the source category. As noted above,

the visibility regulations define BART as

‘‘an emission limitation based on the

degree of reduction achievable through

the application of the best system of

continuous emission reduction.’’ Recent

retrofits at existing sources provide a

good indication of the current ‘‘best

system’’ for controlling emissions. Thus,

for example, recent retrofits for large

utility sources (e.g., sources under the

acid rain program and the Navajo

Generating Station) have commonly

achieved a 90 percent or better rate of

SO2 emissions (at an average cost of

$265 per ton of SO2 removed).105 For

source categories with recently

promulgated NSPS, that standard may

also provide a good indication of the

current ‘‘best system’’ for controlling

emissions. In addition, current

information concerning control

technology performance for many

source categories is available from

EPA’s Clean Air Technology Center,

http://www.epa.gov/ttn/catc. EPA plans

to issue revised BART guidance to

provide updated guidance to the States

on how to calculate BART for purposes

of regional haze within a year of

promulgation of this rule. The EPA will

be developing this guidance through a

national stakeholder process.

Once the State has identified the

retrofit technology that provides the

maximum degree of continuous
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35741

CAA section 169A(g)(2) (emphasis added).

107For areas designated attainment or

unclassifiable for PM2.5, this SIP will be due 12

months after the areas are designated. For areas

designated as nonattainment, this SIP will be due

no later than 3 years after the area is designated

nonattainment. 108 990 F.2d 1531, 1543 (1993).

emission reduction, it should take into

consideration the costs of compliance,

the energy and nonair quality

environmental impacts of compliance,

any existing pollution control

equipment in use at the source, and the

remaining useful life of the source.

Taking these factors into account allows

the State to arrive at an estimate of the

‘‘best system’’ of retrofit control

technology for a particular source and a

corresponding estimate of the likely

emissions which would be achieved by

the imposition of BART. These factors

should be taken into account for each

source subject to BART in order to

compare tradeoffs between the control

efficiencies and costs associated with

various control alternatives.

The remaining factor which the States

must take into account in determining

BART is ‘‘the degree of improvement in

visibility which may reasonably be

anticipated to result from the use of

such technology.’’ In applying this

factor in the context of the regional haze

program, a State should use the degree

of improvement in visibility that would

be expected at each Class I area as a

result of imposing BART, as determined

through the application of the factors

discussed above, on all sources subject

to BART. For the same reasons that the

determination of whether a BARTeligible source may be reasonably

anticipated to cause or contribute to a

visibility problem should be made on a

cumulative basis, EPA believes that a

regional analysis is appropriate for

determining the degree of visibility

improvement that can be achieved

through application of BART. Moreover,

the statute requires the States to

consider ‘‘the degree of improvement in

visibility which may reasonably be

anticipated to result from the use of

such technology.’’ 106 EPA interprets the

language ‘‘from the use of such

technology’’ to refer to the application

of BART level controls to all sources

subject to BART. As a result, EPA

believes that it is reasonable to interpret

this provision as requiring the State to

consider, as part of its source-specific

analysis, the cumulative impact of

applying retrofit controls to all sources

subject to BART to estimate the degree

of visibility improvement which may

reasonably be anticipated to result from

the use of BART.

The EPA also believes that such a

regional analysis provides important

information to the State and to the

public about the magnitude of potential

emissions from sources subject to

BART. This information could be used

to help inform the public debate in

developing reasonable progress goals, in

setting a regional emissions target for a

trading program, and in developing the

overall long-term strategies for making

reasonable progress.

To calculate the degree of

improvement in visibility that would be

expected at each Class I area as a result

of imposing BART on all sources subject

to BART, the State should estimate the

possible emissions reductions resulting

from the application of BART at all

subject sources located within the

region that contributes to visibility

impairment in the Class I area. The State

should work on its own or in

conjunction with other States, such as

in a regional planning body, to

determine the geographic scope of the

region that contributes to each Class I

area. The States should consult with one

another to determine the emission

reductions achievable from sources

subject to BART in other States.

The estimate of possible emission

reductions from sources subject to

BART should be based on the

application of the technology, cost, time

for compliance, energy and nonair

environmental impacts, and remaining

useful life factors discussed above.

Using this estimate, the State will then

need to calculate the resulting degree of

visibility improvement that would be

achieved at Class I areas. The EPA

expects that this exercise will be in the

form of a regional modeling analysis.

The State should use this estimated

degree of visibility improvement in

determining the appropriate BART

emission limitations for specific

sources.

Unless a State commits to regional

planning, a State must include its

source-specific BART determinations in

its initial SIP revision for the area in

which the source is located.107 Where

the State commits to regional planning,

a State may defer submitting its sourcespecific BART determinations

consistent with the timing requirements

described in unit III.B. However, the

State must submit its list of BARTeligible sources at the same time it

submits its committal SIP.

The SIP revision must include the

emission limitations determined to be

BART for sources subject to BART and

a compliance schedule for each source.

Each source subject to the BART

requirement will have to meet the BART

emission limitation within 5 years of

SIP approval, as required under the

CAA. As noted above, within a year,

EPA will be issuing revised BART

guidance to provide States with

assistance in determining BART for

regional haze.

Alternative Measures in Lieu of BART.

In today’s final rule, States may elect to

adopt alternative measures, such as a

regional emissions trading program, in

lieu of BART so long as the alternative

measures achieve more reasonable

progress than would application of

source-specific BART. The EPA believes

that a regional emissions trading

program would be the most efficient

means of achieving BART-level

emission reductions and the emission

reductions needed to meet the States’

reasonable progress goals as

implemented through the States’ longterm strategies.

The EPA believes that this approach

is consistent with the Ninth Circuit’s

decision in Central Arizona Water

Conservation District v. EPA.108 In this

case, the court upheld EPA’s exercise of

discretion to adopt an alternative

emission standard that achieved greater

reasonable progress than would have

been achieved through the imposition of

BART. Allowing States to adopt

alternative measures such as an

emissions trading program rather than

to require BART will provide the States

with the flexibility to achieve greater

reasonable progress towards the

national goal at a lower cost, while still

addressing the Congressional concern

that existing sources contributing to

visibility impairment be required to

control emissions appropriately. The

EPA believes that this best fulfills the

overarching statutory requirement in

section 169A(b) that States make

reasonable progress toward the national

visibility goal, but also ensures that, at

a minimum, the degree of visibility

impairment attributable to BART

sources is addressed by the States

during the first long-term strategy.

Moreover, while an appropriately

designed alternative might result in

differing levels of control at particular

sources than a source-by-source BART

requirement, the environment will

benefit through the achievement of

greater reasonable progress.

As noted above, to take advantage of

the flexibility offered by this provision,

the State must demonstrate that the

alternative measures adopted in lieu of

meeting the BART requirements achieve

greater reasonable progress than would

result from the installation of sourcespecific BART. One way of making this

showing is for a State to show in its SIP

demonstration that the alternative
35742 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

109The State should be able to compare the

degree of visibility improvement through modeling.

For example, for an emissions trading program, the

State may undertake a regional modeling analysis

that simulates least-cost market trades to predict the

geographic distribution of the emission reductions

that could be achieved through a market trading

program and the resultant improvement in visibility

at different Class I areas.

110U.S. Department of Energy, Energy

Information Administration, ‘‘The Effects of Title IV

of the Clean AIr Act Amendments of 1990 on

Electric Utilities: An Update,’’ DOE/EIA–0582(97),

March 1997.

measures will achieve greater emission

reductions and visibility improvement

than would result from meeting the

BART requirements.

In making this showing, States may

rely on the assessments and analyses

developed by regional planning groups

that are formed to address regional haze.

To compare the emissions reductions

and visibility improvement that would

result from application of source

specific BART to that resulting from

implementation of alternative measures,

such as a regional emissions trading

program, the State must estimate the

emissions reductions that would result

from the use of BART-level controls. To

do this, the State could undertake a

source-specific review of the sources in

the State subject to BART, or it could

use a modified approach that simplifies

the analysis.

To simplify the process of arriving at

an estimate of emissions, EPA believes

that one approach that would be

acceptable in place of a source by source

BART analysis would be to consider

some of the BART factors on a categorywide basis. For example, the average

cost per ton of complying with alternate

control technologies and associated

energy and nonair environmental

impacts could be considered on a

category-wide basis. It may be more

appropriate to consider other factors on

a source-by-source basis. For example,

the State could identify the current

control technology in operation at each

source and calculate the emissions that

would be achieved at each source with

a given retrofit control technology or

determine and consider the remaining

useful life of individual sources.

Alternatively, EPA believes it may be

appropriate for the State to combine a

category-wide BART assessment with a

source-specific assessment for certain

sources. For example, if a State can

verify that a source will be retired

within a short period of time, it could

take this into account in determining

BART-level emissions reductions for

that facility while assessing the

remaining sources subject to BART on a

category-wide basis.

The States accordingly have flexibility

in developing a method to determine

the emission reductions that could be

achieved through the application of

BART. Whatever methodology is chosen

by the State to evaluate possible

emissions reductions from BART, the

estimate must reflect at least the

minimum level of emissions reductions

that can be expected. This estimate

becomes the point of comparison for

determining whether an alternative

measure, such as an emission trading

program, achieves greater reasonable

progress toward visibility improvement.

Once the State has arrived at an estimate

of the emissions that would result from

application of source-specific BART, it

should then compare the degree of

visibility improvement expected to be

achieved in Class I areas through the

application of BART to the degree of

visibility improvement projected to be

achieved by the alternative measures

proposed by the State.109 It is not

necessary to go through an additional

analysis of the BART factors in

considering the effects of alternative

measures.

The EPA believes that the most likely

alternative measures adopted by the

States will be an emissions trading

program. There are several advantages

associated with a regional trading

approach in lieu of meeting a sourcespecific BART requirement. First, it

provides flexibility to participating

sources in deciding whether to purchase

credits or to implement on-site emission

reduction strategies, while being

designed to achieve an equivalent level

of emissions. Many commenters felt the

proposal did not provide this type of

flexibility. Second, trading allows

sources to assess the costs of control

technology, alternative fuels, and

process changes across a broad array of

sources and source categories. Thus, a

trading program typically will result in

lower cost per ton of pollutant reduced

than a program which mandates plantspecific technological control. For

example, EPA’s experiences in the acid

rain program have shown that sulfur

dioxide reductions achieved through

market-based programs within the

electric utility sector continue to be

quite cost effective, in the $170—320

per ton range.110 A program which

allows broader trading among sources in

other industrial categories as well

would likely lead to even greater cost

effectiveness for individual sources.

In designing emissions trading

programs that will achieve the requisite

improvement in visibility, States must

ensure that such programs meet several

criteria. First, as noted above, the

legislative history demonstrates

Congress’ recognition of the need to

control emissions from a specific set of

existing sources. Because of the

Congressional focus on control of these

sources, any emissions trading program

must include, at a minimum, the

sources within the trading region

subject to BART. The one exception to

this is where a source has already

installed BART-level pollution control

technology and the emission limit is a

federally-enforceable requirement. In

that case, States may elect to allow a

source the option of not participating in

the trading program.

Second, a trading program adopted in

lieu of BART must be fully

implemented within the period of the

first long-term strategy. To ensure this,

States must provide schedules for

implementing emissions trading

programs with their SIP submittal.

While EPA is allowing States to fully

implement a trading program within the

period addressed by the State’s first

long-term strategy, under section 169A,

BART emission limits are to be

implemented within 5 years. To provide

States with the additional flexibility

they may need to implement a trading

program, EPA has concluded that it is

appropriate for States to have the full

period of the long-term strategy to

achieve the full measure of necessary

emissions. The basis for allowing this

longer implementation period is the

provision that the trading program

achieve greater reasonable progress than

would be achieved by source-specific

application of BART within 5 years of

plan submittal. The EPA will consider

the estimated period of time to

implement the program in determining

whether the alternative measures

‘‘achieve more reasonable progress.’’ In

any event, a trading program adopted in

lieu of BART must be implemented

during the period of the first long-term

strategy.

Third, the reductions in emissions

required of BART sources must be

surplus to other Federal requirements as

of the baseline date of the SIP, that is,

the date of the emissions inventories on

which the SIP relies. In addition,

sources must be required to monitor

their emissions in a way that allows

States and EPA to assure that the

reductions are being achieved. The basic

concept of an emission trading program

is to allow for alternative, cost-effective

ways of achieving equal or greater

overall emissions. To ensure that the

trading program does achieve a greater

overall emission reduction, it is

important that the emission credits are

created by genuine reductions in

emissions. We will be issuing further

guidance to assist States in designing
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35743

their trading programs to ensure that

programs provide such accountability.

Fourth, the regional trading program

may include sources not subject to

BART. Inclusion of such sources

provides for a more economically

efficient and robust trading program.

The EPA believes the program can

include diverse sources, including

mobile and area sources, so long as the

reductions from these sources can be

accurately calculated and tracked.

Fifth, EPA encourages States wishing

to develop such programs to consider

the emission reduction requirements of

other air quality programs. To

implement reductions in a fully

integrated fashion, the State should

consider the extent to which some

sources should be limited in their

ability to trade. Examples of such factors

include the significant contribution to a

local nonattainment situation and the

extent to which trading may assist or

undermine the achievement of greater

progress toward attainment of the

NAAQS or the national visibility goal.

A related issue is the connection

between determinations of BART under

the reasonably attributable regulations

and a trading program adopted in lieu

of BART. The EPA has adopted a

provision in the final rule that allows

States to include a geographic

enhancement in such a trading program

to accommodate reasonably attributable

BART. The purpose for including this

provision is to address concerns

regarding ‘‘hot spots’’—the concern that

some part of visibility impairment in a

specific Class I area is attributable or

uniquely attributable to a single source

or small group of sources because of the

nature and location of the pollution

from the source(s). Should action be

taken by a State (or EPA) to address

reasonably attributable impairment,

these provisions would allow the State

to incorporate methods, procedures, or

processes in a market-based strategy to

accommodate such action.

Sixth, interpollutant trading should

not be allowed until the technical

difficulties associated with ensuring

equivalence in the overall

environmental effect are resolved. Some

other emissions trading programs (e.g.,

trading under the acid rain program)

prohibit emission trades between

pollutants. An emissions trading

program for regional haze might also

need to restrict trades to common

pollutants. Each of the five pollutants

which cause or contribute to visibility

impairment has a different impact on

light extinction for a given particle

mass, making it therefore extremely

difficult to judge the equivalence of

interpollutant trades in a manner that

would be technically credible, yet

convenient to implement in the

timeframe needed for transactions to be

efficient. This analysis is further

complicated by the fact that the

visibility impact that each pollutant can

have varies with humidity, so that

control of different pollutants can have

markedly different effects on visibility

in different geographic areas and at

different times of the year. Despite the

technical difficulties associated with

interpollutant trading today, EPA would

be willing to consider such trading

programs in the future that demonstrate

an acceptable technical approach.

Application for Exemption from

BART. Even where a source may

reasonably be anticipated to cause or

contribute to visibility impairment,

section 169A(c) allows for the

exemption of any source from the BART

requirements if it can be demonstrated

that the source, by itself or in

combination with other sources, is not

reasonably anticipated to cause or

contribute to significant visibility

impairment. In addition, as specified in

section 169A(c)(2) of the CAA, any

fossil-fuel fired power plant with a total

generating capacity of 750 megawatts or

more may receive an exemption only if

the owner demonstrates that the power

plant is located at such distance from all

Class I areas that it does not, or will not,

in combination with other sources, emit

any pollutant which may be reasonably

anticipated to contribute to significant

visibility impairment.

As with the question of whether a

source can be reasonably anticipated to

cause or contribute to any visibility

impairment, EPA believes that the

question of whether a source causes or

contributes to significant visibility

impairment requires an analysis of the

cumulative effects of emission sources

on a region. Regional modeling will be

one appropriate method to determine

whether a source could qualify for the

exemption from the BART

requirements. If a significant cumulative

impact is demonstrated from the sources

across the relevant regional modeling

domain, then any BART-eligible source

in the region would most likely be

found to be reasonably anticipated to

cause or contribute to significant

visibility impairment.

The proposed regional haze rule was

structured such that the BART

exemption provisions in section 51.303

of the existing visibility regulations

would also apply to sources subject to

BART under the regional haze

regulation. In the final rule, EPA has

taken the same approach. Consistent

with section 51.303, a source may apply

to EPA for an exemption from the BART

requirement. The EPA will grant or

deny an application after providing

notice and opportunity for a public

hearing. Any exemption granted by EPA

must have the concurrence from all

affected Federal land managers.

Timing for Submittal of BART

Elements. Because TEA–21 changed the

schedule for submittal of visibility SIPs,

EPA is not requiring States to submit a

list of BART-eligible sources to EPA

within 12 months, as proposed. Under

the final rule, the emission limits or

other measures to address BART under

the regional haze program must be

included in the State’s initial SIP

submittal(s), as discussed further in unit

III.B of this notice, except where the

State commits to regional planning. In

the case where a State opts to work with

other States to develop a coordinated

approach to regional haze by

participating in a regional planning

process, SIP revisions containing the

BART emission limits or alternative

measures in lieu of BART will be due

generally at the time PM2.5

nonattainment SIPs are submitted, but

in no case later than December 31, 2008.

As discussed in unit III.B, States that

submit a commitment to participate in

regional planning are required to submit

the list of BART-eligible sources as part

of that submittal.

I. Monitoring Strategy and Other

Implementation Plan Requirements

Monitoring Strategy

Proposed rule. In the proposed rule,

we included a requirement for States to

develop a monitoring strategy. We

believe that actual monitoring data are

a critical component of any air quality

management approach to visibility

impairment. Data on individual

components of PM (nitrates, sulfates,

elemental carbon, organic carbon,

crustal material) are crucial to

understanding the causes of visibility

impairment at a given location, and

accordingly are necessary for long-term

strategy development. Reviewing these

data with time, and additional data

provided by monitoring sites, are

necessary to understand whether the

long-term strategies are effective.

Under the proposed rule, an initial

monitoring strategy was due 12 months

after promulgation, with periodic

updates every 3 years thereafter.

Requirements for visibility monitoring

are authorized under section

110(a)(2)(B), requiring SIPs to provide

for the monitoring of ambient air

quality, and under section 169A(b)(2),

which authorizes EPA to establish

regulations requiring SIPs to address

‘‘other measures as may be necessary.’’
35744 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

Four separate provisions were

included in the monitoring strategy

requirement: (1) a requirement for States

to provide for additional that is

monitoring ‘‘representative of all Class I

areas,’’ (2) a requirement for States with

Class I areas to assess the relative

contributions of sources within and

outside the State to any Class I area

within the State, (3) requirements for

States without Class I areas to include

a procedure by which monitoring data

will be used to determine the

contribution of emissions from within

the State to Class I areas outside the

State, and (4) a requirement to report all

visibility monitoring data to EPA at least

annually, in accordance with EPA

guidance.

Comments received. Commenters on

this requirement raised a number of

concerns. One concern raised by State

and local agencies was that the costs of

monitoring could be substantial and

urged EPA to provide funding. Other

commenters urged EPA to exercise

flexibility in determining the degree to

which monitors in one Class I area

could be considered representative of

other nearby areas. Other commenters

raised concerns about the feasibility of

monitoring in remote areas and for areas

with difficulty in gaining access to

monitors during the winter.

Commenters also expressed concerns

over the timetable for the monitoring

plan and the requirement for updating

the strategy.

Final rule. Section 51.308(d)(4) of the

final rule includes the requirement for

a monitoring strategy. Under the final

rule, this monitoring strategy is due

with the first regional haze SIP, and it

must be reviewed every 5 years.

Additional sites. Since the 1980’s,

EPA has cooperatively managed and

funded the IMPROVE network with

FLMs and States. Today, the IMPROVE

network of 30 Class I sites (and an

additional network of about 40 sites that

use the IMPROVE methods) collects

data on fine particle concentrations and

on individual particle species. These

individual species (sulfates, nitrates,

elemental carbon, organic carbon,

crustal material) are important for

understanding causes and trends of

visibility impairment at a given

location. The network also employs

optical monitoring methods for the

direct measurement of light extinction,

and scene monitoring methods using 35

millimeter photography.

The EPA is funding the deployment of

several hundred PM2.5 monitors by the

end of calendar year 1999. In order to

meet the requirements for some

monitors to characterize background

conditions and transport patterns, as

well as to more broadly characterize

visibility impairment in Class I areas for

implementation of the regional haze

program, EPA is funding the

deployment of an additional 78

IMPROVE sites for Class I areas by the

end of 1999. As a result of this

anticipated network expansion, we

expect that few, if any, State-funded

monitors will be needed in

implementing today’s final rule. The

IMPROVE Steering Committee is

coordinating closely with the States on

the selection of sites for the expanded

network to help ensure that the new

sites will meet States’ needs for SIP

development. The EPA expects that as

a result of the IMPROVE Steering

Committee process, the expanded

network should provide for data that

can be considered representative of

most if not all Class I areas.

The monitoring strategy must,

however, provide for additional

monitoring sites if the IMPROVE

network is not sufficient to determine

whether reasonable progress goals will

be met. This provision requires States

with Class I areas to work with EPA and

the FLMs to ensure that monitoring

networks provide monitoring data that

are representative of visibility

conditions in each affected Class I area

within the State. We want to clarify that

this provision does not require a

monitor in each Class I area, only that

a monitor be representative of a Class I

area. Accordingly, a monitor in or

adjacent to one Class I area can be

representative of one or more other

Class I areas, based on certain criteria.

Additionally, EPA agrees with

commenters that a few Class I areas may

have severe accessibility problems for

which monitoring may not be feasible.

Use of Monitoring Data to Understand

Contributions to Class I Areas. States

with Class I areas are required to

include in the regional haze SIP a

monitoring strategy that is tailored to a

given representative site. The strategy

must identify the ways that the visibility

monitoring and chemical composition

analysis will be used to understand the

emission sources that contribute to

visibility impairment at a given

monitoring site. Additionally, the

monitoring strategy should identify the

procedures for reviewing monitoring

data and coordinating with other

technical experts. We believe that

continued coordination of visibility

monitoring and chemical composition

analysis among States, FLMs, and EPA

will be important for future regional

planning activities. Analysis of trends in

emissions of those constituents can

assist States in the development of longterm strategies for making reasonable

progress.

The rule also requires monitoring

strategies for States without Class I

areas. We believe it is equally important

for those States to understand and

describe the implications of monitoring

data. First, it is important for those

States to review monitoring information,

including data on the chemical

composition of individual species

concentrations, to help understand the

relative contribution of emissions from

their State to Class I areas in other

States. Second, it is important for these

States to understand and describe how

they will use the monitoring data to

review progress and trends.

Periodic Updates to Strategy. The rule

requires an initial monitoring strategy

and periodic updates. The initial

monitoring strategy is due with a State’s

first SIP submission. Additionally, the

rule requires that the monitoring

strategy be reviewed every 5 years. We

believe that when progress is reviewed

and control strategies are updated, it

will be important to review the

monitoring strategy. For the periodic

updates, States should review the

existing monitoring strategy with the

FLMs and other participating agencies

to assess the need for additional

monitoring sites or modifications to

existing sites, as well as the need for

updated guidance on monitoring

protocols.

Monitoring Guidance. The EPA plans

to issue a visibility monitoring guidance

document soon after promulgating this

rule that will be designed to assist the

States in developing monitoring

strategies. The document will include

technical criteria and procedures for

conducting aerosol, optical, and scene

monitoring of visibility conditions in

Class I areas. The protocols of the

IMPROVE network will be included in

this guidance.

Reporting of Monitoring Data

Proposed Rule. The proposed rule

required States to report all visibility

monitoring at least annually for each

Class I area having such monitoring. We

proposed that States report data in

accordance with EPA guidance and

through electronic data transfer

techniques to the extent possible. There

were no adverse comments on this

reporting requirement.

Final Rule. We have retained a

general requirement in section

51.308(d)(4) that States submit as part of

the SIP a monitoring strategy that

addresses the reporting of visibility

monitoring data to EPA. As noted above,

EPA expects that few, if any, additional

State-funded sites will be necessary to
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35745

111 62 FR 41151.

fully implement the regional haze rule.

Where States do choose to fund

additional sites, however, EPA believes

it is important for the States to make

data from these sites available to EPA

and other agencies.

For monitoring sites in the IMPROVE

network, the IMPROVE Steering

Committee oversees network contractors

who quality assure and consolidate data

from chemical composition analysis of

filter samples. Such data are made

available to all interested parties

through various electronic formats and

online websites. Assuming this practice

continues with the IMPROVE Steering

Committee, States will experience little

or no burden in meeting this

requirement for reporting to EPA.

Annual consolidation of these data

will serve several purposes. First, a

central data base will allow the States

and other interested parties to track

progress over time in relation to

reasonable progress goals. It will also

assist the States in understanding

current visibility conditions as well as

past trends. Consolidation of the data

will assist EPA, the State, other

agencies, and the public in reviewing

the effectiveness of the State’s long-term

strategy for regional haze. Additionally,

consolidation of the data will enable

EPA to better characterize national and

regional visibility trends in its annual

air quality trends report. Finally, a

centralized data base will provide for

the integration of monitoring data from

the new PM2.5 monitoring network and

the visibility monitoring network, both

of which will include PM2.5 and PM10

mass, as well as compositional analysis

by aerosol species. Class I area particle

mass and chemical composition data

can fill important data gaps in defining

regional concentrations for air quality

modeling analyses.

Requirements Under Section 110(a)(2)

of the CAA. Visibility SIP submittals

must document certain program

infrastructure capabilities consistent

with the requirements of section

169B(e)(2) and section 110(a)(2) of the

CAA. Section 169(B)(e)(2) requires

States to revise their section 110 SIPs to

‘‘contain such emission limits,

schedules of compliance, and other

measures as may be necessary’’ to carry

out regulations promulgated pursuant to

this section. The EPA believes that this

language authorizes EPA to ensure that

States review their existing program

infrastructures to ensure that the types

of elements required by section

110(a)(2) for programs addressing the

NAAQS are also sufficient for adoption

and implementation of SIP measures for

regional haze. The final rule does not

include specific provisions addressing

all elements of section 110(a)(2).

However, section 51.308(d)(4)(iv) of the

final rule requires the State to maintain

and update periodically a statewide

inventory of emissions of pollutants that

contribute to visibility impairment.

Where a State is also revising its SIP

to incorporate changes to address the

PM2.5 NAAQS, many of these revisions

may be sufficient to address both PM2.5

and regional haze. The EPA encourages

States to consider the needs of both

programs when updating the provisions

required by section 110 of the CAA to

minimize any administrative burdens.

J. Periodic SIP Revisions and 5-year

Progress Reports

Proposed Rule. The proposed rule

required States to periodically review

and revise their SIPs every 3 years. The

preamble to the proposal stated that

‘‘[t]he EPA believes that a requirement

for regular SIP revisions will result in a

more effective program over time and

provide a focus for demonstrating

ongoing progress and making midcourse corrections in emission

strategies.’’ 111 Each SIP revision would

include a comprehensive review of the

long-term strategy, and a review of

emissions reductions estimates relied on

in the previous plan if the State does not

achieve any reasonable progress target.

The proposal also requested comment

on whether SIP revisions should instead

be required every 5 years. Regarding this

option, EPA also took comment on

whether it should revise the existing

requirement in the ‘‘reasonably

attributable’’ regulations for long-term

strategy reviews from every 3 years to

every 5 years, such that SIP revision

schedules for both regional haze and

reasonably attributable impairment

would be coordinated.

Public Comments. Some commenters

stated that the CAA does not allow EPA

to require periodic SIP revisions.

Several commenters felt that a

requirement to submit comprehensive

SIP revisions every 3 years would be

overly burdensome, and would not

provide enough time to properly

evaluate changes in air quality and

emissions resulting from

implementation of strategies to meet

reasonable progress targets. For this

reason, a number of commenters

supported a 5-year period between SIP

revisions. Several participants in the

GCVTC supported a 5-year review of

progress that meets the procedural

requirements of a SIP revision, but that

also allows for the State to make a

negative declaration if current strategies

are deemed adequate for making

reasonable progress at that time.

Other commenters supported SIP

revisions every 3 years, citing EPA’s

preamble language, which noted that

implementing mid-course corrections

after the 5-year mark may in fact be too

late to correct situations where

impairment is steadily increasing. Some

of these commenters also supported the

3-year cycle for regional haze SIPs since

it would be consistent with the

requirement for 3-year reviews of longterm strategies in the existing 1980

visibility rules.

Authority for Periodic Updates. The

EPA does not agree with commenters

that it lacks the authority to require

periodic SIP revisions. Section

110(a)(2)(F) of the CAA provides that

SIPs are to require ‘‘periodic reports on

the nature and amounts of emissions

and emissions-related data’’ and

‘‘correlation of such reports * * * with

any emission limitations or standards

established pursuant to this chapter.’’

Moreover, section 110(a)(2)(H) requires

SIPs to provide for revision when found

to be substantially inadequate to

‘‘comply with any additional

requirements established under * * *

[the CAA].’’ Both of these provisions

provide EPA with the authority to

require periodic SIP revisions.

The CAA calls for regulations to

protect visual air quality in the Class I

areas in a way that assures prevention

of future impairment in addition to

remedying existing impairment. A onetime review of impairment and

development of strategies to address

that impairment cannot provide such

continuing assurance and, at best, can

only focus on remedying currently

known manmade visibility impairment

within the limits of resources and

technology. A program that did not

anticipate and provide for the need for

future periodic review and revisions,

would not be responsive to the national

goal of preventing any future manmade

visibility impairment.

The requirement for periodic review

of SIP measures also directly responds

to the CAA goal for States to develop

strategies to ensure reasonable progress

toward the national goal of no humancaused impairment. Given that the

statutory factors which States must

consider in determining a reasonable

progress goal include costs of control

and availability of controls, among

others, and given that technology

changes can affect costs and availability

of controls over time, EPA believes that

the requirement for a periodic SIP

revision is appropriate. The periodic

revisions will assure that the statutory

requirement for reasonable progress will
35746 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

112National Research Council, NAS Committee

on Haze in National Parks and Wilderness Areas,

Protecting Visibility in National Parks and

Wilderness Areas, National Academy Press, 1993,

page 10.

113Referring to the example in unit III.F, if the

second implementation plan covers a 10-year

period from 2019 through 2028, then the State

would identify a 3 deciview rate of improvement,

and the amount of visibility improvement that must

be analyzed for the year 2028 would be the 3

deciview improvement for the years 2019 through

2028, plus the 4.2 deciviews of improvement for the

years 2004 through 2018.

continue to be met. The EPA believes

that the need for periodic updates is

also clear from the NAS conclusion that

‘‘achieving the national visibility goal

will require a substantial long-term

(emphasis added) program.’’ 112

Three-year versus 5-year period. In

considering the public comments, EPA

also took into account the body of

evidence indicating a need for

multistate regional planning efforts

under the regional haze program. Past

experience with regional air quality

planning efforts, such as the GCVTC or

the Ozone Tranport Assessment Group

(OTAG), has shown that regional air

quality planning efforts often take 2 or

more years to complete, with additional

time needed for State adoption of

measures and for review and approval

by EPA.

After consideration of the comments

described above, and the timeframes

needed for regional planning, EPA

concluded that a 5-year progress review

and SIP revision cycle is more

appropriate than a 3-year cycle. The

EPA determined that the States will be

better able to assess the effectiveness of

emission management strategies by

considering 5 years of data rather than

3 years since a 5-year period provides

for more stable trend lines for emissions

and air quality changes than a 3-year

period. The EPA also concluded that a

5-year period should result in

significantly less administrative burden

on the States than a 3-year period.

Final rule requirements for

comprehensive plan revisions and

progress reports. The EPA has included

in the final rule, two main requirements

for comprehensive periodic plan

revisions (section 51.308(f)) and

progress reviews (section 51.308(g)).

Section 51.308(f) requires the States to

submit a comprehensive SIP revision in

2018 and every 10 years thereafter. It

must meet all of the core requirements

of section 51.308(d). The BART

provisions of section 51.308(e), as noted

above, apply only to the first

implementation period. Section

51.308(g) requires progress reports for

each Class I area in the State in the form

of SIP revisions every 5 years.

Requirements for comprehensive

periodic plan revisions. Comprehensive

SIP revisions under section 51.308(f)

must include all of the implementation

plan elements found in section

51.308(d) of the final rule. These

elements include, but are not limited to,

the following: (1) reasonable progress

goals for the next 10-year

implementation period, (2)

determination of current conditions and

review of estimates for natural

conditions, (3) a revised long-term

strategy, as necessary to achieve the

reasonable progress goal for the next 10-

year implementation period, and (4)

revised emission inventories, technical

analyses and monitoring strategies. The

EPA wishes to clarify the following

points with respect to the basic core

provisions of section 51.308(d) for the

purpose of periodic comprehensive plan

updates.

Reasonable progress goals. For

purposes of the periodic plan revisions,

the State must select a reasonable

progress goal based upon the statutory

factors discussed above in unit III.F. In

determining the goal for the next

implementation cycle, the State must

include an analysis of the rate of

improvement needed to reach natural

conditions by the year 2064 as an

analytical framework for the plan

revision. To conduct this required

analysis, the State must follow the same

four steps discussed in unit II.F for the

initial plan revision, that is (1)

identification of the difference between

baseline conditions and natural

conditions (noting any updates to the

estimate of natural conditions based

upon technical refinements), (2)

identification of the uniform rate of

progress over the 60-year period that

would be needed to attain natural

conditions by the year 2064, (3)

identification of the amount of progress

that would result if this uniform rate of

progress were achieved during the

period of the regional haze

implementation plan,113 and (4)

identification of reasonable progress

goals in light of the statutory factors,

taking the 60-year analysis into account.

The State must also calculate the

number of years it would take to attain

natural conditions if visibility

improvement continues at the rate of

progress selected by the State as

required in section 51.308(d)(1)(ii).

Reporting of Baseline and natural

visibility conditions. In the SIP

submission for the comprehensive

periodic plan updates, the State must

identify (1) the visibility change from

baseline conditions, (2) the visibility

change since the last SIP revision 10

years ago, and (3) the difference

between current and natural conditions.

Visibility Change from Baseline

Conditions. Section 51.308(f) calls for

States to consider, at the time of any

future SIP revision after the initial

implementation plan, the amount of

visibility improvement achieved from

baseline visibility conditions

(established over the period 2000-2004)

in developing future reasonable progress

goals and associated strategies. The final

rule requires the State to do this by

comparing ‘‘current conditions’’ for the

5 years of most recent visibility data

with baseline conditions. (See

discussion in unit III.E on definition of

‘‘current.’’) Any lack of progress in

improvement of visibility from baseline

conditions will need to be explained in

the SIP revision and considered by the

State in the establishment and/or

revision of new reasonable progress

goals and/or emission management

strategies. Similarly, greater than

expected improvements should be

considered by the State in setting new

visibility goals and emission

management strategies.

If little or no perceptible visibility

improvement has occurred in

comparison to baseline conditions, or if

conditions have actually degraded, then

the State will need to explain the reason

for this degradation in the SIP, and

should seriously consider establishing

more ambitious goals and additional

enforceable measures to achieve these

goals. The EPA will take into account

the amount of progress achieved to date

from the baseline period in determining

whether any future strategy would

ensure ‘‘reasonable progress.’’ If

significant visibility improvement has

occurred from baseline conditions, then

EPA can also take this into account in

reviewing future reasonable progress

goals and strategies.

Visibility Change Since Last SIP

Revision. Section 51.308(f) also calls for

States, in developing reasonable

progress goals for the next 10 years, to

take into account how visibility

conditions have actually changed since

establishment of the previous

reasonable progress goal. (This

provision would apply beginning in the

second SIP revision cycle under the

regional haze program.) If conditions

degraded or failed to meet reasonable

progress goals, the State would be

required to analyze the cause of the

shortfall, and address it as appropriate

in future strategies. If the State has

failed to achieve its reasonable progress

goal for the prior implementation

period, the State would be required to

include in its revision a comparison of

the visibility improvement the State
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35747

expected to achieve to the visibility

improvement the State actually

achieved.

Difference between current and

natural conditions. Section 51.308(f) of

the final rule requires the State, at the

time of any comprehensive SIP revision,

to calculate the difference between

current conditions and natural

conditions for the most impaired and

least impaired days. ‘‘Current

conditions’’ means the conditions for

the most recent 5-year period preceding

the required date of the implementation

plan submittal. This calculation is

needed to determine the total amount of

improvement that States will ultimately

need to address in their long-term

strategies.

Long-term strategies. As for the first

implementation plan, subsequent

comprehensive updates must identify

the enforceable emissions reductions

that will provide for meeting the

reasonable progress goal for Class I areas

within the State and for Class I areas

outside the State which may be affected

by emissions from the State. Unit III.G

provides additional detail on the

requirements of the long-term strategies.

Update of monitoring strategies and

other requirements. The comprehensive

updates are also required to meet the

requirements of section 51.308(d)(4) for

updated monitoring strategies, updated

emission inventories, and other required

technical analyses.

Requirements for 5-year progress

reports. Section 51.308(g) describes the

required elements for progress reports

due every 5 years. For States that

participate in regional planning and

submit initial SIPs in 2008, the first

progress report will be due in 2013. If

a State submits its initial SIP in the

2004–2008 timeframe, its first progress

report would be due before 2013. These

progress reports must follow the same

procedural requirements required for

implementation plan revisions, and the

State must provide the opportunity for

public review and comment. However,

the rule also allows the State to submit

this progress report in the form of a

negative declaration if the State finds

that emission management measures in

the SIP are being implemented on

schedule, and visibility improvement

appears to be consistent with existing

reasonable progress goals. The EPA

intends for progress reports to involve

significantly less effort than a

comprehensive SIP revision.

Each 5-year progress report must

contain the following elements as

specified in section 51.308(g):

• The status of implementation, and

summary of the emissions reductions

achieved, for all emission management

measures implemented within the State

in order to achieve reasonable progress

goals for Class I areas within and

outside the State.

• For each Class I area located in the

State, the report must include

calculations of the following

parameters:

—Current visibility conditions for the

most impaired and least impaired

days.

—The difference between current

conditions and baseline conditions for

the most impaired and least impaired

days.

—The change in visibility for the most

impaired and least impaired days over

the past 5 years.

• An emissions tracking report that

analyzes the change over the past 5

years in emissions of pollutants

contributing to visibility impairment,

disaggregated by source category and

emissions activity, for significant

categories of sources or activities.

• An assessment of whether current

implementation plan strategies are

sufficient for the State or affected States

to meet their reasonable progress goals.

Based on the required calculations

and assessments in the progress report,

the State must take one of four actions

as specified in section 51.308(h). If the

State finds that an additional

substantive SIP revision is not required,

then it may submit a ‘‘negative

declaration’’ to EPA after opportunity

for public review and comment. The

EPA anticipates that if the State is

implementing a reasonable set of

strategies according to the schedule as

developed in the previous

comprehensive SIP revision, and that

visibility trends show that reasonable

progress goals should be achieved over

the 10-year long-term strategy period,

then the State should be able to certify,

through a negative declaration, that no

additional control measures are needed

at the time of this mid-course review.

If the State finds that over the past 5

years there has been a substantial

increase in emissions by intrastate

sources, or there has been a deficiency

in plan implementation, the final rule

requires the State to revise the SIP

within 1 year, rather than waiting for

the next 10-year comprehensive review.

Such a mid-course correction would be

designed to achieve the existing

reasonable progress goal for the relevant

Class I area. The EPA believes that it is

appropriate for the State to take prompt

action to address intrastate problems

since they would not need to participate

in further regional planning.

If the State finds that there is a

substantial increase in emissions or a

deficiency in plan implementation

resulting primarily from interstate

emissions, section 51.308(h)(2) calls for

the State to re-initiate the regional

planning process with other States so

that the deficiency can be addressed in

the next comprehensive SIP revision

due in 5 years. If the State finds that

international emissions sources are

responsible for a substantial increase in

emissions affecting visibility conditions

in any Class I area or causing a

deficiency in plan implementation, the

State must submit a technical

demonstration to EPA in support of its

finding. If EPA agrees with the State’s

finding, EPA will take appropriate

action to address the international

emissions through available

mechanisms. Appropriate mechanisms

for addressing visibility-impairing

emissions from international sources are

further discussed in unit III.G on the

long-term strategy.

If EPA finds that the State has not

been implementing certain measures

adopted into its SIP, or that the State

has submitted a SIP that is not

approvable, or that the State has failed

to submit any required progress report

or SIP revision at all, the State could be

subject to sanctions in accordance with

sections 179(b) and 110(m) of the CAA.

If the State does not resolve the

situation expeditiously, EPA may be

obligated to take further appropriate

action to resolve the situation, including

promulgation of a FIP within 2 years in

accordance with section 110(c) of the

CAA. The EPA believes that in this

regionally-oriented program, it will be

important for States to implement

measures designed to improve visibility

for Class I areas outside of their State,

as well as to improve visibility within

the State. The EPA will exercise its FIP

authority as appropriate and necessary

to ensure that States fulfill their

obligations such that Class I areas make

reasonable progress toward the national

visibility goal.

K. Coordination With Federal Land

Managers

Section 51.308(i) of the final rule

requires that States consult with FLMs

before adopting and submitting their

regional haze SIPs. This requirement is

consistent with the proposed regional

haze rule and the 1980 regulation for

‘‘reasonably attributable’’ visibility

impairment. A number of commenters

expressed a concern that this provision

was not equitable, in that States are

required to consult with FLMs, but the

rule does not require FLMs to consult

with States before they take action, even

when actions such as prescribed

burning could have a significant impact
35748 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

114See 56 FR 57522, Nov. 12, 1991.

115CAA Section 169B(d).

116A Clean air corridor is defined as a region that

generally brings clear air to a receptor region, such

as the Class I areas of the Golden Circle.

117See GCVTC Report, pp. i–iii.

118 62 FR 41141.

119 62 FR 41146.

on a State’s visibility program. These

commenters recommended that the

proposed rule be amended to mandate

a two-way communication.

The EPA agrees that it is important

and necessary for FLMs to consult with

States on visibility-related issues. Landuse activities on Federal lands can have

impacts on nearby areas of a State, and

there have been significant air quality

issues related to these activities. In

recent years, FLMs have undertaken

activities to improve communications

with States. There are a number of

examples of these efforts. The IMPROVE

steering committee, the group that

oversees FLM efforts to monitor

visibility in Class I areas, includes

representation from State agencies.

Recently, State representation on this

committee was expanded by adding two

more State members. Another example

are the memoranda of understanding

that FLMs have entered into with States

to coordinate prescribed burning

activities. The EPA believes that the

FLM agencies generally recognize the

importance of involving States in the

development and implementation of

land use policies and other actions that

affect States’ abilities to make air quality

improvements.

The EPA believes that it is

unnecessary to impose an

administrative requirement on another

agency of the sort requested by

commenters in a Federal rule, because

Federal agencies are already subject to

compliance with SIP requirements in

the same manner, and to the same

extent as any nongovernmental entity

through section 118, as discussed

below. The EPA will, however, be

working with FLMs and States to assist

in their communications over air quality

issues.

Commenters also expressed concerns

that emissions from Federal agencies are

beyond their jurisdiction. These

commenters felt that if States were not

able to regulate such emissions, then

other sources within the State would be

treated inequitably under the final rule.

The EPA does not agree that Federal

sources are beyond a State’s

jurisdiction. As required by section 118

of the CAA, if a State air quality

regulation affects a given type of source

within its jurisdiction, Federal facilities

having that type of source must comply

with the State regulations in the same

manner, and to the same extent as any

nongovernmental entity. Thus, FLMs

having emission sources of the type that

are covered by State air quality

regulations are subject to the same

extent as private sector entities.

IV. Treatment of the GCVTC

Recommendations

A. Background

The EPA established the GCVTC on

November 13, 1991.114 The purpose of

the GCVTC was to assess information

about the adverse impacts on visibility

in and around 16 Class I areas on the

Colorado Plateau region and to provide

policy recommendations to EPA to

address such impacts. Section 169B of

the CAA called for the GCVTC to

evaluate visibility research as well as

other available information ‘‘pertaining

to adverse impacts on visibility from

potential or projected growth in

emissions from sources located in the

region.’’

The GCVTC was required to issue a

report to EPA recommending what

measures, if any, should be taken to

protect visibility.115 The CAA required

that, at a minimum, this report was to

consider: (1) The establishment of clean

air corridors,116 (2) the need to impose

additional new source review

requirements in any clean air corridors,

and (3) additional restrictions on

increases in emissions which may be

appropriate to protect visibility in

affected Class I areas. The GCVTC was

also required to address the

promulgation of regulations addressing

long-range strategies to address regional

haze in the region. In June 1996, the

GCVTC issued its recommendations to

EPA.

The GCVTC recommendations

covered a wide range of control strategy

approaches, planning and tracking

activities, and technical findings. The

primary recommendations of the

GCVTC covered nine categories of

activities: 117

• Air pollution prevention and

reduction of per capita pollution as a

high priority, including non-binding

targets on production of electricity from

renewable energy sources;

• Tracking the effect of new sources

of emissions on clean air corridors;

• Closely monitoring stationary

source emissions, establishment of

regional targets for sulfur dioxide

emissions for the year 2000 and the year

2040 with interim targets to be

established in the future, exploration of

a similar tracking system for other

pollutants, and the development of

market-based regulatory programs if

emissions targets are not met;

• Emissions reductions in and near

Class I areas;

• Capping of mobile source emissions

for areas contributing to visibility

impairment, and State support for

national measures aimed at further

reducing tailpipe emissions;

• Further assessment of the

contribution of road dust to visibility

impairment;

• Future binational collaboration to

resolve technical and policy concerns

about contributions to visibility

impairment on the Colorado Plateau

resulting from emissions from pollution

sources in Mexico;

• Implementation of smoke

management programs to minimize

effects of all fire activities on visibility;

and

• The need for a future regional

coordinating entity to follow through on

implementing the recommendations.

Proposed rule. In the July 31, 1997

proposal of the regional haze rule, EPA

included an extensive review of the

recommendations of the GCVTC.118 The

preamble discussed how several

concepts from the GCVTC’s

recommendations were incorporated

into the proposed framework for the

national regional haze program. For

example, EPA proposed an approach for

tracking reasonable progress, based on

improving conditions on the worst

visibility days and not allowing

conditions on the best days to degrade,

that was consistent with both the

GCVTC’s definition of ‘‘reasonable

progress’’ and with the CAA national

visibility goal of remedying any existing

impairment and preventing any future

impairment. The proposal also called

for tracking of continuous emissions to

inform State control strategy decisions

on a periodic basis.119

However, in its proposal, EPA chose

not to incorporate the GCVTC’s specific

emission management strategies as

direct requirements for SIPs. The EPA

followed this approach because the

proposed rule was designed to establish

a national framework for development

of SIPs to remedy regional haze

visibility impairment in all Class I areas

nationwide. In addition, it was not clear

how the various elements of the

GCVTC’s report were to be translated

into SIP requirements. The EPA noted

in the proposal that the ‘‘Commission’s

recommendations have components that

contemplate implementation through a

combination of actions by EPA, other

Federal agencies, States and Tribes in

the region, and voluntary measures on

the part of the public and private
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35749

120 62 FR 41142.

121 62 FR 41143.

122 62 FR 41143.

123Written Testimony of John S. Seitz, Director,

Office of AIr Quality Planning and Standards, U.S.

Environmental Protection Agency, before the

Subcommittee on Forest and Public Land

Management of the Committee on Energy and

Natural Resources, United States Senate, October

28, 1997.

124 Docket A–95–38, Item # VIII–G–76.

125 63 FR 46952.

entities throughout the region.’’ 120 The

EPA indicated that such a mixture of

activities made it difficult for EPA to

directly require States to implement all

of these measures in their SIPs. Instead,

the EPA specifically sought public

comment on the manner in which the

national regional haze program

framework, as proposed, would allow

for implementation of the GCVTC’s

recommendations.121 The EPA also

solicited comment on whether to adopt

the GCVTC’s stationary source strategies

with or without modification.122

The EPA also reiterated its position in

testimony before the United States

Congress, stating that ‘‘we specifically

designed the regional haze rule to allow

for implementation of the GCVTC’s

recommendations to address the

environmental goal of improving

visibility.’’ 123

In public meetings and written

comments following the proposal,

interested parties expressed concern

that the proposed rule did not

specifically endorse or incorporate the

GCVTC’s recommendations. Some

commentors asserted that the rule

‘‘ignored’’ the recommendations. The

EPA also received numerous comments

that supported adoption of the GCVTC

recommendations as part of the national

regional haze rule. In particular, several

commentors who believed that EPA’s

proposed rule did not adequately

support the GCVTC’s recommendations

asserted that EPA’s participation in the

GCVTC implied that strategies

developed to address visibility in Class

I areas of the Colorado Plateau would be

taken into account within the structure

of the rule. Commentors also noted that

EPA’s proposal of a visibility target and

requirements to address BART left a

high degree of uncertainty as to whether

the GCVTC recommendations could

form the basis for SIPs.

On June 29, 1998, after the close of

the public comment period on the

proposed regulations, the WGA sent to

EPA additional comments on the

proposed regional haze rules. These

comments contained specific new

language for addressing the

recommendations of the GCVTC. The

comments offered provisions to be

included in the national regional haze

rule to allow certain western States to

submit SIPs to assure reasonable

progress in addressing regional haze

impacts on the Colorado Plateau based

upon the technical work and policy

recommendations of the GCVTC.124 The

transmittal letter signed by Michael O.

Leavitt, Governor of the State of Utah,

reemphasized the commitment of

Western governors to the GCVTC

recommendations, and requested that

EPA take public comment on their

suggested preamble and rule language as

part of the EPA process in reaching

decisions on a final regional haze rule.

In response to this submittal, on

September 3, 1998, EPA published a

notice of availability in the Federal

Register.125 The notice solicited public

comment on the contents of the WGA

letter and EPA’s translation of the

letter’s requirements for SIPs into draft

regulatory language. The comment

period for the notice of availability

closed on October 5, 1998 and EPA

received approximately 125 comments.

In summary, most of the commentors

supported the adoption of provisions to

directly address the GCVTC

recommendations in the national rule,

although many requested changes to the

draft regulatory language. Some

commentors expressed concern over

how these provisions would relate to

the national rule, in particular to the

national provisions for BART. Other

commentors addressed the way in

which the WGA letter and EPA’s draft

regulatory language translated the

GCVTC’s recommendations. In addition,

some commentors expressed concern

over the timing of the SIP submittals

both over the linkage to timing of SIP

submittals for ozone and PM2.5 SIPs and

the requirements of TEA–21.

Commentors also requested EPA to

commit to consider the national

transportation measures noted by the

GCVTC as part of EPA’s responsibility

toward helping the States make

reasonable progress.

In the final rule, EPA is establishing

specific SIP requirements which may be

used by the States and tribes that

participated in the GCVTC to satisfy the

national regional haze rule. These SIP

requirements will form a basis for these

States to meet the CAA requirements for

reasonable progress in the 16 Class I

areas addressed by the GCVTC Report.

These SIP requirements acknowledge

and give effect to the substantial body

of work already completed by the States

and tribes participating in the GCVTC.

The Agency, therefore, and for reasons

explained in more detail below,

provides these SIP requirements as an

optional way for these States and tribes

to implement the national rule based on

the merits of the work of the GCVTC

completed before establishment of the

national framework. The EPA finds that

the GCVTC actions to date address, or

provide a mechanism to address, the

statutory factors for assessing reasonable

progress required by the CAA. The EPA

is satisfied that the GCVTC’s strategies

as set forth in section 51.309, when

supplemented by the annex process

discussed below, will provide for

‘‘reasonable progress’’ toward the

national visibility goal for the 16 parks

and wilderness areas addressed by the

GCVTC. Consequently, if a State

submits a plan that addresses the

requirements of section 51.309,

including the requirements related to

the annex, as described below, that plan

will be considered to comply with the

national rule’s requirement for

reasonable progress for the period from

plan approval to 2018.

Today’s final rulemaking, including

section 51.309, is directly responsive to

the western States’ and tribes’

comments calling for recognition of the

policy development efforts of the

GCVTC. At the same time, the rule

allows for future cooperative efforts

among the GCVTC States, so that the

national requirements for ensuring

reasonable progress are fully addressed.

This action exemplifies how the

regional haze protection provisions can

be flexible and allow for a broad range

of emissions control strategies tailored

to a specific region. This action fully

recognizes the GCVTC and its follow-up

body, the WRAP, as a valid regional

planning process to address, at a

minimum, the 16 Class I areas that were

the focus of the GCVTC. Section 51.309

provides for continued work of the

GCVTC, which may be accomplished

through the WRAP, to establish a

complete framework which can be

adopted in the SIPs for addressing all

sources of visibility impairment in the

16 Class I areas. The section also sets

forth provisions for addressing

additional Class I areas that were not

directly addressed in the GCVTC report.

Section 51.309 does not preclude

States from developing and adopting

their own control strategies. Rather, it

provides an expedited process whereby

a State choosing to follow the GCVTC’s

recommendations in its SIP can rely

fully on the technical analyses, policy

recommendations, and agreements

reached by the GCVTC members,

thereby significantly reducing the effort

required to establish federally

approvable SIPs. A State remains free to

develop and submit a SIP to EPA which

does not rely on the GCVTC’s work or
35750 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

section 51.309. Such a State will be

fully subject to the requirements and

schedules set forth in section 51.308, in

the same manner and to the same extent

as the States and tribes throughout the

United States that did not participate in

the GCVTC process.

B. General Requirements of Section

51.309

Section 51.309 requires specific

emissions control strategies for a broad

region of the Western United States and

includes measures which address

different types of emissions sources,

including stationary, area and mobile

sources. Some of these strategies are

already in place while others, such as

mobile source provisions and the

structure of a market trading system to

assure compliance with stationary

source emissions goals, will require

development of additional regulatory

measures. A review of each element of

section 51.309 is found in unit IV.C

below.

The GCVTC recommended emission

reduction targets from stationary

sources of SO2 for the years 2000 and

2040. The GCVTC did not recommend

quantitative interim targets between the

years 2000 and 2040. Therefore, in

addition to provisions for specific

emissions strategies, section 51.309

allows for an annex to the GCVTC report

which will be considered in establishing

specific targets for SO2 emissions from

stationary sources in the region between

2003 and 2018. This annex process and

EPA’s approval of acceptable interim

emissions targets for SO2 will be key in

completing a series of strategies that can

be deemed by EPA as meeting

reasonable progress for the Class I areas

on the Colorado Plateau.

The provisions for adoption of

strategies consistent with the GCVTC

recommendations do not preclude the

States and tribes from developing

additional control strategies for

achieving reasonable progress in other

Class I areas. Nor do they preclude

States and tribes which did not

participate in the GCVTC, but which

may benefit from its strategies due to the

geographic proximity of their Class I

areas to the State where strategies will

be implemented and regional transport

throughout the west, from building on

these strategies to address reasonable

progress for their Class I areas. However,

for all Class I areas not on the Colorado

Plateau, the States and tribes would

need to demonstrate, through the

required analyses, that implementation

of these strategies would contribute to

meeting the requirements of section

51.308. By focusing first on

implementation strategies for the 16

Class I areas based on the

recommendations of the GCVTC, all

western States may reduce the technical

and administrative costs of addressing

the remaining Class I areas by building

on the outcome of existing programs

rather than requiring the development

of two programs in parallel.

In the national rule, EPA is requiring

States to analyze the rate of progress in

visibility improvement that would be

needed to reach natural conditions

within 60 years. The analyses must

assess what strategies are available to

meet that rate for the period of the longterm strategy. The GCVTC reviewed the

period from 1990 to 2040 to assess what

strategies were reasonable to achieve

visibility improvement in the 16 Class I

areas. The GCVTC’s Alternatives

Assessment Committee developed a

modeling system linking emissions

control strategies, the costs of such

strategies and the degree of visibility

improvement that would result from

those strategies. While not specifically

attempting to reach natural conditions

within 60 years, a key emissions control

scenario assessed in the GCVTC process

was a ‘‘maximum management

alternative.’’ The GCVTC looked at

many source types and their impacts on

visibility. This specific assessment

applied all known and anticipated

control strategies over the time period as

an indicator of the maximum amount of

improvement in visibility possible in

the region. The results of this analysis

did not show sufficient emissions to

reach natural conditions in any

mandatory Class I area by 2040. The

analysis of this scenario did, however,

demonstrate that the ‘‘maximum

management alternative’’ is not likely to

be achievable based on technological,

economic and policy choices made by

the Alternates Assessment Committee

due to costs, degree of visibility

improvement and other factors.

Consequently, EPA finds this analysis,

plus the management alternatives

chosen (i.e., market-based emissions

reductions, specific source-sector

reductions, etc.) to be an acceptable

basis for approvable SIP strategies for

the 16 Class I areas for the first longterm strategy period since, in effect,

reaching natural conditions by 2040 was

shown not to be reasonable in this

transport region at this time. In making

this finding, EPA concludes that the

GCVTC analyses and process provide

for an assessment comparable to that

called for by section 51.308.

In promulgating section 51.309, EPA

is establishing specific SIP requirements

for the time period 2003 through 2018

based on demonstrations by the GCVTC.

The EPA finds the GCVTC

demonstrations satisfy requirements for

review of the statutory factors as

provided for under subsection

51.308(d).

While the GCVTC’s assessment

included projections to the 2040, EPA

feels that the strategies incorporated in

section 51.309 must be re-evaluated in

2018 to assure that they will continue to

achieve reasonable progress after a

thorough review of the CAA factors. As

discussed elsewhere in today’s notice,

this periodic review and revision of

regional haze SIPs is needed because of

technological changes and economic

factors which are likely to significantly

alter both the rate of emissions growth

within a region, and the degree to which

new technologies can more effectively

reduce emissions, both of which can

affect the rate of visibility improvement.

In addition, the requirement for periodic

revisions is consistent with the statutory

provisions governing long-term

strategies.

The EPA agrees with commentors

who noted certain benefits to following

the pathway provided through section

51.309 for addressing regional haze

impairment. First, there is the benefit

that the mixture of required strategies

for the 16 Class 1 areas has already been

through public comment as part of the

GCVTC deliberations and subject to

review by many stakeholders. This

previous public debate should help

ensure broader public support for the

State’s plans as they are adopted and

implemented. As pointed out by

commentors, one of the benefits of the

GCVTC recommended strategies is that

they are aimed at developing costeffective control strategies and ensuring

compliance flexibility for affected

sources. For example, the strategy to

address emissions from stationary

sources uses a milestone and backstop

emissions trading program mechanism.

This rewards voluntary emissions

reductions since a regional emissions

trading program would only become

effective if regional milestones are

exceeded. Given that the provisions for

the milestone and backstop emissions

trading system may be approvable in

lieu of BART, depending on the

milestones developed in the annex, full

compliance with BART emissions

limitations would not be required

within 5 years of plan submittal, as

would be required of States which

submit plans under section 51.308

requiring source-specific BART. In

addition, the economies of scale offered

by the work of the WRAP in conducting

coordinated assessment activities, such

as economic and air quality modeling,

could be substantial in aiding States in

meeting their planning obligations.
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35751

Finally, EPA’s provisional view that

SIPs which meet section 51.309 would

satisfy the requirement for reasonable

progress minimizes the analyses

required of States which adhere to the

requirements of section 51.309,

compared to States making an

independent submittal under section

51.308.

C. Elements of the GCVTC-Based State

and Tribal Implementation Plans

1. Time Period

Section 51.309(d)(1) establishes the

time period of the plan to cover the 16

parks and wilderness areas for the

period 2003 through 2018. The GCVTC’s

recommended emissions reduction

strategies, including the emission

reduction approach for stationary

sources of SO2, establish the long-term

strategy requirements for plan

submittals to EPA until the year 2018.

This time period is consistent with the

submittals required under section

51.308 which will be due between 2004

and 2008 depending on the

classification of State areas with respect

to attainment of the recently

promulgated NAAQS for PM2.5. The

time period covered by the plan revision

due under section 51.309, 2003–2018, is

somewhat different from the timeframe

for long-term strategies required by

section 51.308 for the Class I areas not

on the Colorado Plateau. The differences

that exist acknowledge the substantial

early work of the GCVTC, on the 16

Class I areas, while at the same time

making the strategy review cycle

consistent with the timetable

established in section 51.308.

The EPA received comment that it

should allow the GCVTC

recommendations to be the basis of all

future strategies to address regional haze

for the 16 Class I areas on the Colorado

Plateau permanently. The EPA

disagrees. No given set of emissions

strategies can be determined reliably to

achieve reasonable progress into the

distant future. While the GCVTC

strategies adopted by the States under

the provisions of section 51.309 may

well continue to be adequate to meet the

future long-term strategy requirement, a

full review of emissions strategies for all

Class I areas of the region is appropriate

to assure that ‘‘reasonable progress’’ is

being achieved and will continue to be

achieved during the periods of

subsequent long-term strategies. As

noted above, the relevant facts

concerning costs of controls, availability

of control strategies, and other statutory

factors will change over time.

Advancements in technology and

changes in economic factors will likely

provide opportunities for

implementation of new cost-effective

control measures to assure reasonable

progress. The structure of EPA’s rule is

designed to require States, through the

SIP process, to review the statutory

factors on a periodic basis and

determine appropriate changes to their

strategies based on that review.

2. Projection of Visibility Improvement

Section 51.309(d)(2) requires the plan

to contain a projection of the visibility

conditions expected through the year

2018 and to take into account the

measures required in the GCVTC report

and the provisions of section 51.309.

This projection must, at a minimum, be

expressed in units of deciview.

The Agency received comment that

the GCVTC States should not be

required to estimate visibility

conditions using the deciview metric,

but should be permitted simply to track

emissions over time. While EPA

encourages States to track emissions in

order to evaluate the emission reduction

effectiveness of adopted control

measures, it is equally important that

changes be translated into visibility

improvements in order to be responsive

to the national goal. As noted earlier in

unit III.C of this notice on the deciview

metric, EPA’s selection of the deciview

scale is an appropriate way to do this.

The Agency also included this provision

to ensure that the public understands

the relationship of the SIP to visibility

conditions at the Class I areas and to the

national goal of no manmade

impairment in visibility in these areas.

The Agency thus feels that it is

appropriate to inform the public on the

relationship between chosen emissions

control measures and their effect on

visibility by requiring States to report on

actual and expected changes in

visibility to be achieved through

implementation of section 31.309.

Those changes can be based on

monitored data as well as estimated for

future conditions based on

implementation of emissions strategies.

Moreover, the requirement for use of the

deciview metric does not prevent the

States from using other indicators, in

addition to the deciview, for describing

regional haze conditions, such as

standard visual range or atmospheric

light extinction.

3. Treatment of Clean Air Corridors

Section 51.309(d)(3) requires the

States to identify a geographic region or

regions which will be subject to a

comprehensive emissions tracking

strategy. The purpose of such

comprehensive emissions tracking is to

ensure that the frequency of clear days,

or days with good visibility, increases or

does not decrease at any of the 16 Class

I areas addressed by the GCVTC. This

section of the rule is designed to make

the review of emissions, and their

resulting impact on the clear days at the

Class I areas, part of the public record

through the SIP approval process. It

does not mandate any emissions control

strategies specifically aimed at

improving clear days, but provides for

the State to periodically review the need

for such strategies. If anthropogenic

emissions create visibility impairment

above natural conditions, and if overall

annual human-caused emissions

reductions take place in a region, it is

likely that visibility will improve for

both the most impaired days and the

least impaired days.

The geographic area (or areas) to be

covered by the emissions tracking

strategy is to be determined initially

based on the GCVTC Meteorology

Subcommittee’s report entitled Clean

Air Corridors: A Framework for

Identifying Regions that Influence Clean

Air on the Colorado Plateau. The

geographic area (or areas) can be further

refined based on new technical findings

over time. The requirement to track

emissions will enable States to quickly

determine if changes in patterns of

emissions will reduce the number of

clean air days (defined as the average of

the 20 percent clearest days) in any of

the 16 Class I areas. The State must

analyze the effects of the emissions

changes and implement additional

measures to protect the clean days if

necessary. The States may include the

tracking of emissions for the clean air

corridors with tracking of emissions for

other purposes such as compliance with

stationary source emissions targets, if

appropriate. The EPA notes that clean

air corridors will be protected by other

implementation plan requirements,

such as other SIP measures that may

apply to existing stationary sources.

States may wish to rely on technical

cooperation now beginning under the

WRAP as an efficient means to

consolidate efforts on emission

inventories and projections needed to

monitor clean air corridor emissions

and their effects on clear air days.

4. Implementation of Stationary Source

Reductions

To achieve the reductions in

emissions for stationary sources

projected in the GCVTC’s strategies,

subsection 51.309(f)(1)(i) requires the

establishment of SO2 emission

reduction milestones as part of the

development of an annex to the GCVTC

report. Section 51.309(d)(4) requires

monitoring and reporting of stationary
35752 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

126 GCVTC Report, pp. 38–46.

source emissions of SO2 in order to

assess compliance with these milestones

during the period 2003 to 2018. The SIP

must contain criteria and procedures for

implementing a market trading program

or other program documented in the

SIP, consistent with section

51.309(f)(1)(i), if triggered by emissions

exceeding the emissions reduction

milestones. In particular, the SIPs must

provide for implementation of the

market-based program or other

emissions control strategy as called for

by an assessment of SO2 emissions for

the years 2003, 2008, 2013, and 2018.

States must fully activate the market

system or other program within 1 year

after an assessment showing the

excessive emissions. In addition, the

implementation plan must provide for

all affected sources to comply with the

market system or other programs

allocating emissions within 5 years after

the date the program is triggered. The

rule also requires States to report on

actual emissions reductions and

compare them to the established

milestones. If a market trading program

or other program is triggered, the rule

requires States to report whether all

sources covered by the market trading or

other programs are in compliance with

applicable requirements.

In addition to requirements for

control of emissions of SO2, the rule

requires the State to explore emission

management options for stationary

source emissions of PM and NOX. The

States are required to report by 2003 on

their consideration of the need for

emissions targets for these pollutants to

prevent growth in emissions of these

pollutants in the region as a whole. The

EPA believes that the States should base

their decisions on the need for, and

levels of, emissions targets for these

pollutants on the degree to which such

pollutants contribute to regional haze

impairment in the Class I areas

addressed by their SIPs. The States must

report to EPA by 2003 on their decisions

whether to develop targets and

additional control strategies for PM and

NOX emissions from stationary sources.

If the States determine that such targets

and controls are needed, they must

submit a plan revision to EPA not later

than December 31, 2008 containing any

necessary long-term strategies and

BART or other requirements for

stationary sources of PM and NOX.

In adopting the requirements for

stationary source emission reduction

milestones in this manner, EPA is

indicating that the State’s adoption of

approvable SO2 milestones and a

backstop market trading program as set

forth in section 51.309(f) in addition to

the other requirements in section 51.309

would provide for reasonable progress

for the 16 Class I areas for the

implementation period from 2003 to

2018. The emissions reductions

provided for by the milestones and

trading program must address the BART

provisions in section 51.308(e). For the

reasons discussed in the portion of this

preamble concerning BART

requirements, EPA believes that the

GCVTC’s adoption of a market based

alternative to source-by-source BART

will permit the GCVTC States to meet

the provisions of the national rule

which allow the use of alternative

measures in lieu of BART.

Implementation of the framework

established by subsections 51.309 (d)(4)

and (f) will thus satisfy the provisions

for an alternative measure in lieu of

BART for regional haze impairment set

forth in section 51.308(e)(2), provided

the interim milestones called for in the

annex assure greater reasonable progress

than would be achieved by application

of BART. The EPA will supplement its

actions on the stationary source strategy

with future rulemaking on the States’

submission of interim milestones for

SO2 emissions as part of the annex. In

reviewing the interim milestones, EPA

will be informed by the annex to the

GCVTC report provided for in section

51.309(f) to be discussed later.

5. Mobile Sources

Section 51.309(d)(5) requires

implementation plans to address the

contribution to regional haze by

emissions from mobile sources. This

mobile source provision is based on the

finding in the GCVTC Report that

reducing total mobile source emissions

is an essential part of any long-term

strategy for management of visibility on

the Colorado Plateau.126 The GCVTC

found that some urban areas will

already be developing mobile source

emissions budgets and programs to meet

other CAA requirements. To the extent

that mobile source emissions in these or

other areas are found to contribute

significantly to visibility impairment in

the Class I areas of the Colorado Plateau,

the GCVTC recommended that an

emissions budget be established for any

area with a significant contribution to

the regional mobile source emissions

total. The GCVTC called for the budgets

to be established beginning in the

approximate year in which emissions

from mobile sources are projected to be

at their lowest point during the

planning period of 2003 to 2018, which

is expected to be in 2005. The emissions

budget should serve both as a planning

objective and a performance indicator

for that area.

Accordingly, today’s final rule

requires all plans to provide for an

inventory of current and projected

emissions (VOC, NOX, SO2, elemental

carbon, organic carbon, and direct fine

particles) from mobile sources for the

2003 to 2018 period. Because, as noted

in the GCVTC Report, the inventory for

the year 2005 is expected to represent

the expected lowest total emissions

from mobile sources in the planning

period, that inventory must be included

in the SIP. Once State inventories have

been compiled and evaluated, the States

with urban areas found to contribute

significantly to visibility impairment in

the 16 Class I areas must establish and

document their mobile source emissions

budgets for any such area. In addition,

the States must establish SIP

components which limit VOC, SO2,

NOX, elemental and organic carbon and

direct fine particulate mobile source

emissions to their projected lowest

levels for the period 2003 to 2018. The

State plans must also provide for the

implementation of measures to achieve

the mobile emissions budget, and for

demonstrations of compliance with any

such budget. The demonstrations must

include a tracking system to evaluate

and demonstrate the State is meeting its

share of the regional mobile source

emissions budget.

The GCVTC report also noted that the

Federal government has a role in

addressing mobile source emissions.

The GCVTC report identified several

national mobile source-related

emissions reduction strategies under

consideration by EPA that are important

to visibility conditions in the Class I

areas on the Colorado Plateau. The

GCVTC agreed to promote these

initiatives on a national level. With

regard to ongoing development of

policies and regulations on emissions

from mobile sources, the June 29 letter

from the WGA requests that EPA ‘‘make

a binding commitment in its final

regional haze rule to fully consider the

GCVTC’s recommendations’ on several

national mobile source emissions

control strategies. Comment on the

regional haze rule specifically requested

that EPA commit to consider

development of a list of very specific

national mobile source emissions

control strategies.

The EPA agrees with the GCVTC’s

conclusion that emissions from mobile

sources can be significant contributors

to regional haze visibility impairment.

The EPA is currently working on a

number of the strategies the GCVTC

requested us to ‘‘fully consider’’ and the
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35753

127 GCVTC Report, p. 47. 128See Id.

summary below indicates the status of

activities under way.

No. Measure Status of EPA efforts to fully consider the measure

1 .............. Adoption of the 49-State LEV standard in 2001 and Tier II vehicle emission standards in year 2004 (if determined to be more

effective).

Combined Tier II/gasoline sulfur NPRM is being drafted, with

publication expected in early to mid-1999.

2 .............. Support of EPA’s current proposal for new on-road, heavy-duty

vehicles emission standards that reduce NOx emissions by at

least 50 percent over the 1998 requirements in the CAA, while

maintaining current stringent PM emission limits.

Finalized 2004 standards for on-road heavy-duty in 10/97 [62

FR 54693]; reductions in NOx emissions and secondary PM.

3 .............. Pursue additional PM reductions from on-road vehicles .............. Potential actions being evaluated.

4 .............. Pursue additional engine emission standards for new off-road

vehicles (heavy-duty, construction-type) that provide reasonably achievable reductions.

Finalized standards in 8/98 [63 FR 56967]. Also planning a technology review by December 2001 to evaluate feasibility standards and additional reductions.

5 .............. Explore broader application of and additional reductions in the

sulfur content of both gasoline and diesel fuel.

Gasoline sulfur control-rulemaking underway.

Considering regulation of diesel fuel sulfur.

6 .............. Promotion of cleaner-burning fuels ............................................... In first year of implementing clean-fuel fleets program. The Office of Mobile Sources presented a series of fleet manager

workshops during May, June and July of ’98. Clean Fuel Fleet

Program Implementation Guidance was issued in August ’98.

We have a team within OMS working on promoting clean fuels

efforts.

7 .............. Pursue fuel standards and control strategies for diesel locomotives, marine vessels/pleasure craft, airplanes, and Federal

vehicles as described in the GCVTC’s Report.

Study of these issues is ongoing, but no specific actions have

been scheduled.

8 .............. Support requirements for effective refueling vapor recovery systems that capture evaporative emissions.On-board re-fueling standards for cars and trucks finalized October 1996.

We may consider refueling systems for on-road, heavy-duty gasoline in future.

The EPA will continue to work with

States and regional planning entities to

help them assess how national mobile

source emissions strategies will affect

other strategies needed to ensure

reasonable progress toward the national

visibility goal during the

implementation of the regulations

promulgated today. The EPA will also

grant States full credit for

implementation of future national

mobile source programs in emissions

strategies needed to attain reasonable

progress goals.

6. Emissions Related to Fire

Section 51.309(d)(6) requires

documentation that all prescribed fire

programs within the State consider and

address the effects of smoke on visibility

when planning and issuing permits for

prescribed fires. The GCVTC Report

stated that ‘‘fire has played a major role

in the development of and maintenance

of most ecosystems in the West.’’ 127 In

addition, the report notes ‘‘emissions

from fire (wildfire and prescribed fire)

are an important episodic contributor to

visibility-impairing aerosols, including

organic carbon, and particulate matter

(PM2.5)’’. Agricultural burning emissions

and their effects have been identified as

a concern by the GCVTC but have not

been quantified due to lack of data. The

GCVTC concluded that all types of fire

(prescribed fire, wildfire, and

agricultural burning) must be addressed

equitably as part of a visibility

protection strategy.128

The EPA agrees with the GCVTC’s

conclusions and is including in this

section of the rule a requirement for the

States to address all types of fire in

fulfilling the requirements of this

section and in submitting SIPs for

approval by EPA. Section 51.309(d)(6)

requires each State to establish an

emissions inventory and tracking

system (spatial and temporal) for VOC,

NOX, elemental carbon and organic

carbon, and direct fine particulate

emissions from prescribed fire, wildfire,

and agricultural burning. The EPA

believes that such information could be

developed on a regional basis and could

be accomplished through mechanisms

such as recording acres experiencing

fire and calculating emissions based on

vegetation type and soil moisture. Most

importantly, the rule requires the

establishment of enhanced smoke

management programs for fire that

consider visibility effects, in addition to

health and nuisance objectives, and

calls for programs to be based on the

criteria of efficiency, economics, law,

emissions reduction opportunities, land

management objectives, and reduction

of visibility impacts. The

comprehensive approach envisioned by

the rule will allow States to plan a

smoke management program that

minimizes visibility impacts but also

fully recognizes the ecological role of

fire.

The smoke management plans must

address all sources of fire used for land

management purposes. The provisions

of this section also provide for

establishment of annual emissions goals

for fire (excluding wildfire) that will

minimize increases in emissions to the

maximum extent feasible. These goals

are to be established cooperatively by

States, tribes, State and Federal land

management agencies, and their private

sector counterparts, considering factors

similar to those identified for enhanced

smoke management plans.

7. Dust From Roads

Section 51.309(d)(7) requires States to

assess the impact of dust emissions on

regional haze visibility in the 16 Class

I areas. If such dust emissions are

determined to be a significant

contributor to visibility impairment, the

State must implement emissions

management strategies to address their

impact. In the technical work of the

GCVTC, road dust was not shown to be

a major contributor to regional haze

impairment based on current

monitoring data. However, work on

future emissions projections of road

dust emissions was directly tied to

growth in vehicle miles traveled (VMT).

The large increase projected for the west

in VMT over the planning period of the

GCVTC report resulted in initial
35754 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

129 GCVTC Report, p. 46.

130See id.

131 GCVTC Report, p. 28.

132 GCVTC Report, p. 7.

predictions of a very large contribution

of road dust to regional haze.129 This

technical result was addressed in the

GCVTC report and the GCVTC

discounted the predictions of the future

impacts from road dust. However, the

GCVTC recommended that its policy

conclusion that distant road dust is not

likely to play an important role in

regional haze should be confirmed

through further tracking of road dust

emissions. The GCVTC also emphasized

that road dust control should be

considered in locations ‘‘in and near’’

Class I areas.130 The EPA agrees with

this approach and has included the

assessment of road dust as a

requirement of the SIP. In addition,

today’s action requires appropriate SIP

measures over time based on the

contribution of road dust to regional

haze.

8. Pollution Prevention

This section addresses the GCVTC’s

recommendations on pollution

prevention and renewable energy. The

GCVTC goal recommended that

renewable energy comprise 10 percent

of the regional power needs by 2005 and

20 percent by 2015. The Administration

has recently offered legislation

proposing a national mandate of 7.5

percent by 2010. The Commission’s goal

represents the outcome of its consensus

process and is a more aggressive goal

than what the Administration has

proposed as a national mandate. As

with other GCVTC recommendations,

the EPA has included this provision in

this rule in recognition of the overall

body of the GCVTC’s work and believes

it is consistent with the provisions of

the national rule. Section 51.309(d)(8)

requires the State to summarize all

pollution prevention plans currently in

place, inventory the current and

expected energy generation capacity

through 2002, the total energy

generation capacity and production for

the State, the State’s percentage of total

energy generation and capacity that

comes from renewable energy sources,

and the State’s anticipated contribution

toward the GCVTC’s goal that renewable

energy comprise 10 percent of the

regional power needs by 2005, and 20

percent by 2015.

The GCVTC found that to prevent

further degradation of vistas in the west,

it would be necessary to combine costeffective pollution control strategies

with a greater emphasis on pollution

prevention, including low or zero

emission technologies and energy

conservation. It further found that there

was a high potential for renewable

energy production, especially electrical

energy, and that the relative cost of

renewable energy production is

declining over time. The GCVTC cited

forecasts of renewable energy

production by the Western Systems

Coordinating Council and by the Land

and Water Fund of the Rockies in

support of its adoption of the goal that

10 percent of regional power needs be

served by renewable energy sources by

the year 2005 and 20 percent by the year

2015.131

In establishing assessment and

reporting requirements for the States,

EPA is supporting the GCVTC Report’s

promotion of renewable power

production. Such production will likely

be based on emerging renewable energy

technologies such as wind, solar,

biomass, and geothermal. The EPA also

supports tracking annual goals for

increases in renewable power

generation in the transport region.132

The GCVTC identified strategies which

the States could rely on to help achieve

this regional renewable energy goal,

including, but not limited to, focusing

research funding for renewables,

financial incentives, and requiring new

power generation projects to include a

portion of the generation from

renewable energy sources. The EPA

notes that the WRAP is committed to

following through on the GCVTC’s

recommendations and can assist the

States in developing strategies they can

rely on to achieve regional renewable

energy goals contained in the GCVTC

Report.

In response to the GCVTC’s

recommendations on pollution

prevention, section 51.309(d)(8) calls for

each SIP to provide for incentives to

reward efforts that go beyond

compliance and/or achieve early

compliance with air pollution related

requirements. The plan also must

identify specific areas where renewable

energy has the potential to supply

power where it is not now provided by

current service systems and where

renewable energy systems are most cost

effective. The plan must contain

projections of the short-term and longterm emissions reductions, visibility

improvements, costs savings, and

secondary benefits associated with

renewable energy goals, energy

efficiency and pollution prevention

activities. The plan must also contain a

description of the programs being relied

on to achieve the State’s contribution

toward the GCVTC’s renewable energy

goals.

The State must provide a

demonstration of its progress toward

achieving the renewable energy goals in

2003, 2008, 2013 and 2018. The

demonstration must include

documentation describing the potential

for renewable energy resources, the

percentage of renewable energy

associated with new power generation

projects implemented or planned, and

the renewable energy generation

capacity and production in use or

planned within the State. Where a State

cannot feasibly meet its planned

contribution to the regional renewable

energy goals, the State must identify the

measures implemented to achieve its

contribution and explain why meeting

the State’s contribution was not feasible.

Commentors on EPA’s September 3,

1998 notice of availability stated that

incorporation of language from the

WGA letter on renewable energy

restricts State and local energy planning

since a SIP is federally enforceable

under the CAA. Commentors also

expressed the opinion that the

requirements for SIPs to address

renewable energy goals may overstep

EPA’s legal authorities which are

limited to emissions limitation and

pollution performance standards.

The EPA disagrees that the provisions

of section 51.309(d)(8) impermissibly

restrict State and local energy planning

or that these provisions exceed EPA’s

authority under the CAA. As stated

previously, the requirements of section

51.309 are provided to GCVTC States as

an alternative to the general provisions

of section 51.308 as a means of giving

effect to the policy and technical work

of the GCVTC. The goals themselves are

not enforceable and States are not

required to meet the renewable energy

goals. However, as the WGA letter and

the GCVTC provide, these provisions

are not severable. States which wish to

take advantage of the GCVTC’s efforts

and EPA’s acceptance thereof are

obligated to meet all of the requirements

of section 51.309.

Rather, EPA is setting enforceable

requirements for the States to assess

progress toward goals established by the

GCVTC with respect to renewable

energy production as a means for

reducing dependence on more polluting

forms of energy production. States

participating in the GCVTC strategy are

responsible for explaining why they

cannot meet the GCVTC goals. The

required reporting by the States will

inform the public of air quality

improvements that would result from

that goal had it been realized. It is the

relationship between renewable energy

production and associated

environmental effects (direct and
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35755

indirect) that is the thrust of the

assessment and reporting effort under

the SIP.

9. Implementation of Additional

Requirements

In section 51.309(d)(9), EPA requires

SIPs to provide for implementation of

other GCVTC Report policy and strategy

options that can be practicably included

as enforceable emissions limits,

schedules of compliance or other

enforceable measures to make

reasonable progress toward the national

visibility goal for the 16 Class I areas.

The GCVTC’s recommendations

included items that are not appropriate

to directly translate to SIP requirements

for every State. The EPA supports State

choice of appropriate actions on other

options and measures identified by the

GCVTC and has, therefore, established a

general provision for SIPs calling for

them to consider and adopt additional

measures as necessary and appropriate.

The rule further requires States to report

to EPA in 2003, 2008, 2013, and 2018

on what measures have been adopted

and the status of implementation of

those measures.

10. International Transport of Pollution

One of the additional areas of concern

noted in the GCVTC report, for instance,

relates to effects of emissions from

sources outside of the territory of the

United States. As stated elsewhere in

this notice, the EPA will not hold States

responsible for developing strategies to

‘‘compensate’’ for the effects of

emissions from foreign sources.

However, the States should not consider

the presence of emissions from foreign

sources as a reason not to strive to

ensure reasonable progress in reducing

any visibility impairment caused by

sources located within their

jurisdiction. The States retain a duty to

work with EPA in helping the Federal

government use appropriate means to

address international pollution

transport concerns. Indeed, such efforts

are under way. The EPA and other

Federal officials are working with

representatives of the Mexican

government to complete a study which

will assess the contribution of fossil-fuel

fired electric generation stations in

northern Mexico to haze in Big Bend

National Park. These efforts and funding

of work to establish emissions

inventories in Mexico will help address

concerns raised by the GCVTC. In

addition to activities directly related to

visibility effects, there are other efforts

underway related to the United StatesMexico border health issues. Given that

emissions contributing to health effects

and those contributing to visibility

impairment are generally the same, the

border studies and emissions

inventories will help support

assessment of regional visibility

conditions. In addition to work with

Mexico, EPA routinely meets with

representatives of the Canadian

government on issues related to

transport of air pollutants, particularly

focusing on emissions affecting acidic

deposition. The EPA intends to

continue to work through appropriate

channels in building technical

information and addressing policy

concerns related to international

pollution transport.

11. Periodic Implementation Plan

Revisions

Section 51.309(d)(10) requires the

States to periodically assess their

progress in implementing measures for

protection of visibility. This includes a

review of how the measures

implemented under section 51.309 are

consistent with the national rule’s

provisions for long-term strategies and

BART. The assessments must be

completed by 2008, 2013, and 2018 and

must be submitted to EPA as SIP

revisions that comply with the

procedural requirements of sections

51.102 and 51.103. As with any other

review and revision of SIP

requirements, States will be expected to

use the most current available technical

methods and procedures in conducting

their assessments.

The provisions of section

51.309(d)(10) further require that where

a State concludes that planning

adjustments are necessary as a result of

emissions occurring within the State, it

revise its implementation strategies to

include rule revisions that are effective

within 1 year after the State makes such

a conclusion in order to assure

reasonable progress at any of the 16

Class I areas on the Colorado Plateau.

States may also conclude, based on their

assessments, that no changes to the plan

are needed, and the plan revision

requirement can be met by submitting a

‘‘negative declaration’’ as an

implementation plan revision to EPA.

This revision must provide the State’s

basis for finding that no changes are

needed. This submission will provide

the public with necessary information

and an opportunity to comment on the

State’s findings.

The EPA views the requirement of

section 51.309(d)(10) as a periodic

check on progress rather than a

thorough revision of regional strategies.

The State interim assessments should

focus on significant failures or shortfalls

in implementing adopted strategies and

on emissions from in-State or out-ofState sources which may be causing

degradation in regional haze visibility

but were not anticipated in the

development of the original plan and

will, therefore, not be addressed by

currently-adopted programs. If a State

makes such findings with respect to inState sources, EPA expects the State to

revise its SIP, reducing emissions to be

consistent with the regional planning

effort reflected in the reasonable

progress SIPs due in 2003. If transport

of emissions from out of State is

suspected of impairing reasonable

progress, the State should identify this

to EPA and should initiate cooperative

efforts with upwind States so the

emissions can be more fully evaluated

and, as needed, addressed in the next

mandatory full SIP revision. This

requirement is virtually identical to the

provisions for periodic review under

sections 51.308(g) and (h).

12. State Planning and Interstate

Coordination

Section 51.309(d)(11) provides

flexibility to a State to address its

contribution to visibility impairment

through the regional emissions control

strategies discussed above. The SIP

strategies to protect the 16 Class I areas

on the Colorado Plateau can thus be

developed through interstate

coordination in a regional planning

process. Such regional planning can

help a State develop documentation of

the technical and policy basis for the

individual State apportionment of

emissions and visibility impairment, the

contribution to emissions addressed by

the State’s plan, coordination in the

analysis of interstate transport and

control of pollution with other States,

and compliance with other criteria for

approval of SIPs under CAA sections

110 and 169A and B. Therefore, under

today’s final rule and EPA policy, States

may rely on regional entities’ efforts to

develop and document technical and

policy support for the SIPs required by

this rule. For the purposes of

implementing the requirements of

section 51.309, EPA recognizes the

WRAP as a regional planning group for

purposes of interstate consultation

under section 51.308(c).

As indicated in the introduction to

the section of today’s notice addressing

the WGA and GCVTC

recommendations, States retain the right

to develop their own programs with or

without reliance on the work products

of a regional entity. In the case where a

State chooses to develop a SIP without

reliance on a regional planning process,

however, the State will need to show

how it accounted for the effect of its

emissions on Class I areas which may be
35756 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

133See 63 FR 7254 (Feb. 12, 1998). 134 GCVTC Report, p. x–xi.

located beyond the State’s borders, as

well as the effect of upwind emissions

from other States on the Class I areas

within its borders.

The regional haze SIP for a State

choosing not to implement the

requirements of section 51.309,

including the SIP submittal deadlines,

would be governed by the national rules

provided in section 51.308. Any State

choosing not to adopt a SIP in

accordance with the GCVTC strategy

and optional approach in section

51.309, but wishing to use the WRAP

mechanism for regional cooperation in

developing its SIP requirements, would

need to comply with all of the

requirements outlined in the national

rule in section 51.308.

13. Tribal Implementation Plans

The WGA called for EPA’s final rule

to permit tribes within the GCVTC

Transport Region to implement

visibility programs, or reasonably

severable elements, in the same manner

as States, regardless of whether such

tribes have participated as members of

a visibility transport GCVTC. The EPA

has not included the WGA’s

recommended rule provision in today’s

action because the necessary authority

for tribal organizations has already been

provided in a previous EPA

rulemaking.133 The EPA does, however,

agree with the position expressed in the

WGA recommendation. The EPA wishes

to clarify that tribes may directly

implement the requirements of this

section of the regional haze rule in the

same manner as States. The Tribal

Authority Rule provides for this, as

discussed further in unit V of today’s

notice. The independence of tribes

means that a tribal visibility program is

not dependent on strategies selected by

the State or States in which the tribe is

located. If tribes within the Transport

Region decline to implement visibility

programs and EPA finds that emissions

management strategies are needed to

assure reasonable progress, EPA will

work with the appropriate tribes

directly to provide for Federal

implementation of appropriate

emissions reduction strategies. This is

based on the government to government

principles of Federal-Tribal relations.

D. Requirements for States Electing Not

To Follow All Provisions of the Section

51.309(e)

The EPA notes that the provisions for

allowing the Transport Region States to

adopt SIPs based on the GCVTC

recommendations requires that States

endorse the range of strategies

recognized by the GCVTC. A State

electing not to implement the GCVTC

recommendations as set forth in section

51.309(d) must address all of its Class I

areas and any Class I area to which its

sources’ emissions may contribute to

impairment under the provisions of

section 51.308. In addition, any

Transport Region State must advise

other States electing to comply with

section 51.309 of the nature and effect

of their program on visibility impairing

emissions so that other States can use

this information in developing programs

under section 51.309. This provision

assures that all components needed to

address reasonable progress are part of

SIPs either under the provisions of

section 51.309 or section 51.308.

E. Annex to the GCVTC Report

1. Interim Milestones

Section 51.309(f) calls for an annex to

the GCVTC Report for the purpose of

completing the program requirements to

meet reasonable progress under the

CAA, including submission of a

complete long-term strategy and

addressing the BART requirement for

the 16 Class I areas on the Colorado

Plateau. The purpose of the annex is to

develop interim emissions milestones

for stationary source SO2 interim targets

between the year 2000 target and the

target for the year 2040. Under section

51.309(f)(1)(i), the States must consider

four specific factors in setting the

interim emission milestones. The first

factor affecting the selection of interim

milestones is the GCVTC’s definition of

reasonable progress. The GCVTC notes

in its report that the term ‘‘reasonable

progress’’ refers to ‘‘progress in reducing

human-caused haze in Class I areas

under the national visibility goal.’’ 134 It

goes on to note that ‘‘the CAA indicates

that ‘reasonable’ should consider the

cost of reducing air pollution emissions,

the time necessary for compliance, the

energy and non-air quality

environmental impacts of reducing

emissions, and the remaining useful life

of any existing air pollution source

considered for these reductions.’’ The

discussion also includes the GCVTC’s

Public Advisory Committee definition

that ‘‘progress towards the national

visibility goal is achieving continuous

emissions reductions necessary to

reduce existing impairment and attain

steady improvement in visibility in

mandatory Class I areas, and managing

emissions growth so as to prevent

perceptible degradation of clean air

days.’’ Together, these provisions call

for the achievement of continuous

emissions reductions and tracking the

reductions to ensure visibility

improvement in hazy days and visibility

maintenance on clear days. To be

consistent with and responsive to the

guiding principles, recommendations

and strategies adopted by the GCVTC,

EPA expects any interim targets to

demonstrate a significant continuous

downward trend in emissions and not

postpone significant progress to periods

covered by future long-term strategies.

The second factor is the quantifiable

target for 2040 to which interim targets

must contribute. This target is a 50 to 70

percent reduction by 2040 in emissions

from stationary source SO2 emissions,

based on the projection of the GCVTC’s

baseline forecast scenario from actual

1990 emission levels. Interim targets

should reflect assessment of reasonable

measures which reduce regional

loadings of SO2. Such assessments may

include examination of interim targets

based on costs per ton of reducing SO2

in line with recently adopted control

measures.

The third factor is the applicable

requirements of the CAA for making

reasonable progress and implementing

BART. As noted previously in this

preamble, the CAA requires a long-term

strategy to ensure reasonable progress

and the application of BART to certain

large sources that are reasonably

anticipated to cause or contribute to

regional haze. The rule requires the

annex to address the BART provisions

of the national rule. As noted in the

earlier discussion of BART, EPA will

accept alternative measures, such as

regional emissions trading programs,

which achieve greater reasonable

progress in lieu of meeting the sourcespecific BART requirement. As noted

elsewhere in the preamble, EPA plans to

issue revised BART guidance within a

year. During the next year and a half,

EPA also plans to issue new or revised

guidance related to the design of

emission trading programs, including

guidance on the structure of economic

incentive programs. Given this

schedule, EPA intends to work closely

with the WRAP as it develops the

annex, its approach to meeting the rule’s

BART requirements and its backstop

market-trading program. The EPA

believes that its participation in the

WRAP will help to ensure that the way

in which the annex addresses BART and

the market trading program will be

compatible with EPA’s revised BART

guidance and any new or revised

guidance EPA issues related to

emissions trading programs.

In the event EPA finds that the annex

does not meet the rule’s BART

provisions because it is inconsistent
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35757

with EPA’s revised BART guidance, the

Transport Region States may submit a

revised annex to address any

deficiencies. The revision should be

submitted as expeditiously as

practicable but no later than 12 months

from EPA’s determination that the

annex is deficient with respect to BART

due to its inconsistency with the BART

guidance. Similarly, if EPA finds the

annex does not meet the provisions of

any EPA guidance applicable to markettrading programs that is issued after

promulgation of this rule, the Transport

Region States may submit a revision to

the annex to remedy any such

deficiencies. These revisions should

also be submitted no later than 12

months from EPA’s determination that

the annex cannot be incorporated in the

SIP because of inconsistencies with the

guidance. The EPA expects that the

States and WRAP stakeholders will

make every effort to address both the

revised BART guidance and any new or

revised emission trading program

guidance within the timeframe

established by section 51.309 for

submittal of the annex. By providing for

EPA participation in the WRAP,

encouraging State and stakeholder

efforts to respond expeditiously to new

or revised guidance, and calling for any

needed revisions to the annex to be

submitted within a year from an EPA

determination of deficiency, this

approach will ensure compliance with

the SIP submittal deadlines in section

51.309(c).

The fourth factor to be addressed in

the setting of interim milestones is the

timing of implementation plan

assessments of progress and the

identification of mechanisms to address

cases where emissions exceed milestone

levels for the reporting years 2003, 2008,

2013 and 2018. This schedule is

designed to achieve eventual

coordination of target years with

assessments for regions affecting other

Class I areas. Because these efforts call

for continuing consultation and sharing

of information between regions as well

as between States, timetables for further

work by the GCVTC States are designed

to bring the GCVTC States’ long-term

strategy updates in line with the

schedule for the next long-term strategy

update required of all other States.

2. Documentation of Market Trading or

Other Alternative Measures To Assure

Reasonable Progress.

In addition to the interim targets,

section 51.309(f)(1)(iii) requires the

annex to contain final documentation of

the market trading program or other

programs to be implemented by the

GCVTC States if current implementation

plans and voluntary measures are not

sufficient to meet the established

interim milestones. This documentation

must include model rules, memoranda

of understanding, and other materials

necessary to describe in detail and

establish in enforceable fashion how

emission reduction progress will be

monitored, what conditions will require

the market trading program to be

activated, how allocations will be

performed, and how the program will

operate.

3. Additional Class I Areas

An additional provision, section

51.309(g) allows States to elect to

demonstrate reasonable progress for

other Class I areas within the Transport

Region States beyond the original 16

areas addressed by the GCVTC’s

assessment, relying on the strategies

recommended by the GCVTC. See the

discussion in unit IV.F. of this

preamble.

4. Geographic Enhancements

The EPA has also adopted provisions

in subsections 51.309(b)(7) and

51.309(f)(4) that would allow the

Transport Region States to establish a

process as part of a broad regional

strategy, such as backstop markettrading program, to accommodate the

situation where a State takes action to

address reasonably attributable BART

under the provisions of section

51.306(c)(2). As noted elsewhere, the

annex, if approved, will allow the

Transport Region States to submit a SIP

which adopts an alternative measure in

lieu of BART. The purpose for including

the provisions regarding geographic

enhancement is to address the

intersection between the existing

reasonably attributable BART provision

and regional haze BART, which may be

met through an emissions trading

program such as the milestone/backstop

market-trading program which is to be

included in the annex. Existing rules

address ‘‘hot spots’—those situations in

which part of the visibility impairment

in a specific national park or wilderness

area is reasonably attributable to a single

source or small group of sources in the

airshed because of the nature and

location of the pollution relative to the

Class I area. Should action be taken by

the State to address such reasonably

attributable impairment through BART,

the geographic enhancement provisions

would allow the backstop market-based

trading program to accommodate such

action. These provisions parallel a

similar allowance in subsections

51.301(ii) and 51.308(e)(2)(C)(v).

The EPA is repeating these

provisions, with minor language

changes, to be clear that they apply to

both the milestones or backstop markettrading program provided for in the

annex. Subsection 51.309(b)(7) defines

the term geographic enhancement for

the provisions governing the annex and

section 51.309(f)(4) allows the annex to

contain a geographic enhancement.

Similar to the national program, these

provisions will allow the market trading

system included in the annex to

accommodate situations where a State

wishes to require BART control

measures on sources or a small group of

sources due to reasonably attributable

impairment and that source has been

included in the backstop market trading

program under the annex. In this

situation, the milestone or backstop

market-trading program may include a

level of reasonably attributable

impairment which may require

additional emissions reductions over

and above those achieved under the

quantitative emissions reductions

milestones established for regional haze.

5. The EPA Responsibilities in Relation

to the Annex

Section 51.309(f)(3) spells out EPA’s

responsibilities with respect to the

annex and calls for EPA to publish the

annex upon receipt. The EPA must then

conduct a review and decide, after

notice and opportunity for public

comment, whether the annex meets the

requirement of section 51.309(f)(1) and

whether it assures reasonable progress.

If EPA finds the interim targets and

accompanying documentation meet the

requirements of reasonable progress,

then it will incorporate the interim

targets into the stationary source SIP

requirements in section 51.309(d)(4)

within 1 year of receipt, after public

notice and comment. If EPA decides

that the annex does not meet SIP

requirements for reasonable progress or

if EPA does not receive an annex, it will

notify the GCVTC States, who will then

be subject to the general provisions of

section 51.308 in the same manner as

other States.

One commentor on the annex

approach described in EPA’s September

3 notice of availability noted that the

WGA letter set forth a tight timetable for

development of the market system and

that it appears to violate the TEA–21

requirements. In response, EPA notes

that these are the timetables established

by the GCVTC in 1996 and which have

been the basis for work by the followup body of the WRAP. With respect to

TEA–21, the colloquy between Senator

Allard and Senator Baucus in the

Congressional Record on the conference

report concerning implementation of

GCVTC recommendations is instructive,
35758 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

135 144 Cong Rec. SS407 (daily ed. May 22, 1998).

and EPA believes that it fully addresses

the commentor’s concern. Senator

Baucus stated that ‘‘[TEA–21] clarifies

that it does not affect EPA’s authority to

provide for State implementation of the

agreements and recommendations set

forth in the June 1996 GCVTC Report on

a schedule consistent with the GCVTC’s

Report. * * * The conferees added

specific language so as not to preclude

the Administrator from providing for

earlier State implementation of the

GCVTC’s agreements and

recommendations * * *.’’ 135 That

language states that:

The preceding provisions of this paragraph

shall not preclude the implementation of the

agreements and recommendations set forth in

the GCVTC Report dated June 1996.

TEA–21 section 4102(c)(2).

F. Additional Class I Areas

Section 51.309(g) calls for Transport

Region States to identify in their 2003

plan submissions whether they elect to

meet the provisions of section 51.308 or

51.309 in establishing their long-term

strategy and BART requirements for

additional Class I areas not covered by

the original GCVTC effort. By no later

than December 31, 2008 the States

electing to use section 51.309 to address

additional Class I areas must submit

plan revisions which include a

modeling demonstration establishing

expected visibility conditions on the

most-impaired and least-impaired days

at the Class I areas for which they seek

to demonstrate reasonable progress.

These demonstrations may be

conducted by the State or based on

refined studies conducted by regional

entities. The plan must include the

analyses required in section

51.308(d)(1). The plan can build upon

and take full credit for the strategies

adopted for the 16 Class I areas. It must

also contain any additional measures

beyond those strategies that may be

needed to demonstrate reasonable

progress in those areas, in accordance

with the provisions of section

51.308(d)(1) through (4). As provided

for in section 51.309(g)(2), a Transport

Region State may have until no later

than December 31, 2008, to submit a

plan for additional Class I areas, which

is the date for submission that

additional Class I areas under section

51.308. Transport Region States may

well benefit by addressing the

additional Class I areas under section

51.309, since using the same rule

provision for both sets of Class I areas

could facilitate coordination of the

requirements for the areas as well as

enabling consolidation of plans after

2008.

Furthermore, if the State can develop

the necessary demonstration for other

Class I areas before 2003, a Transport

Region State could submit one

implementation plan in 2003 covering

both the 16 Class I areas and other Class

I areas for which it must assure

reasonable progress.

V. Implementation of the Regional Haze

Program in Indian Country

This section discusses how the

requirements of the regional haze rule

relate to emissions released from Indian

country.

A. Background on Tribal Air Quality

Programs

Before discussing how the regional

haze rule affects tribes, we believe it is

useful to briefly describe EPA’s overall

policy and rulemaking efforts on tribal

air quality programs.

On November 8, 1984, the EPA

released a policy statement entitled

‘‘EPA Policy for the Administration of

Environmental Programs on Indian

Reservations.’’ This policy statement,

available on the Internet at http://

www.epa.gov/indian/1984.htm, stresses

a number of themes. In particular, this

policy stresses that EPA, consistent with

overall Federal government policy, will

pursue the principle of Indian ‘‘selfgovernment,’’ and that it will work with

tribal governments on a ‘‘government-togovernment’’ basis. The policy

statement also emphasizes EPA’s desire

to work with interested tribal

governments in developing programs

and in preparing to assume regulatory

and environmental program

management responsibility for Indian

country. The EPA will retain

responsibility for protecting tribal air

quality until such time as tribes

administer their own air quality

protection programs.

The CAA, as amended in 1990, added

a new section 301(d) which authorizes

EPA to ‘‘treat tribes as States’’ for the

purposes of administering CAA

programs. Section 301(d) required that

EPA promulgate regulations listing

specific CAA provisions for which it

would be appropriate to treat tribes as

States and establishing the criteria that

tribes must meet in order to be eligible

for such treatment under the CAA. The

EPA proposed these regulations on

August 25, 1994 (59 FR 43956), and

finalized the rule on February 12, 1998

(63 FR 7254). Much of the regulatory

language in this rule is codified in the

Code of Federal Regulations (CFR) as a

new 40 CFR part 49. This rule is

generally referred to as the Tribal

Authority Rule or TAR.

The TAR includes general eligibility

requirements for tribes interested in

assuming program responsibilities that

are codified in section 49.6 of the rule.

These eligibility requirements are

designed in part to ensure that such

tribes have the infrastructure needed to

successfully implement a tribal air

quality program. Tribes may request a

formal eligibility determination using

administrative procedures contained in

49.7. Tribes may also use the

administrative procedures in 49.7 to

seek approval to implement CAA

programs. The TAR authorizes EPA to

review requests for eligibility

determinations and program approvals

simultaneously. As noted in 49.7(c),

tribes that are interested in seeking EPA

approval to implement air quality

programs under the CAA may request

approval to implement only partial

elements of a CAA program, so long as

the elements of the partial program are

‘‘reasonably severable.’’

Section 301(d)(4) of the CAA confers

discretionary authority on EPA to

provide, through regulation, alternative

means to ensure air quality protection in

cases where it determines that treating

tribes as ‘‘identical’’ to States would be

inappropriate. Accordingly, in

promulgating the TAR, EPA provided

flexibility to tribes seeking to implement

the CAA. Some flexibility is established

by virtue of EPA’s decision, under 49.4

of the final rule, not to treat tribes as

States for specified provisions of the

CAA. The rationale for this approach is

discussed on pages 7264 and 7265 of the

preamble to the final rule, and in unit

III.B of the preamble to the proposed

rule. For example, unlike States, tribes

are not required by the TAR to adopt

and implement CAA plans or programs,

thus tribes are not subject to mandatory

deadlines for submittal of

implementation plans. As discussed in

the preamble sections identified above,

EPA believes that it generally would not

be reasonable to impose the same types

of deadlines on tribes as on States.

Among the CAA provisions for which

EPA has determined it will not treat

tribes as States is section 110(c)(1) of the

CAA, which requires EPA to intervene

and ensure air quality protection within

2 years after a State either fails to adopt

a SIP or does not win EPA approval for

a SIP that was determined to be

deficient. The EPA did not apply this

provision to tribes because the section

110(c) obligation on EPA to promulgate

a FIP is based on failures with respect

to required submittals, and, as noted

above, tribal submissions under the

TAR are voluntary, not mandatory.
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35759

Instead, pursuant to its section 301(d)(4)

discretionary authority, EPA has

provided in the TAR that, where

necessary and appropriate, it will

promulgate FIPs within reasonable

timeframes to protect air quality in

Indian country. See 40 CFR 49.11(a).

B. Issues Related to the Regional Haze

Program in Indian Country

Today’s final rule imposes

requirements for revisions to SIPs. The

rule requires States to develop SIP

revisions to address regional haze, to

update the SIP every 10 years, and to

continue to evaluate progress toward the

national visibility goal. The

requirements of today’s final rule are

among those air quality programs for

which tribes may be determined eligible

and receive authorization to implement

under the TAR. Tribes wishing to

assume these regional haze program

requirements and be ‘‘treated as States’’

may seek approval under 40 CFR 49, but

are not required to do so. Where tribes

do not take on this responsibility, EPA

will ensure air quality protection in

Indian country consistent with the

provisions of 40 CFR 49.11(a).

We encourage tribes to participate in

regional planning efforts for regional

haze. A good example of tribal

participation in regional haze planning

is the efforts of tribal representatives on

the GCVTC. These efforts are continuing

with tribal participation on the WRAP.

The EPA expects, as noted above, that

additional regional planning groups will

be formed in reaction to today’s final

rule. A number of tribes have indicated

interest in participating in regional

planning efforts, and we believe this is

beneficial in many respects. Tribal

participation can help provide

emissions inventory information that

can serve to better understand the

importance of sources in Indian country

to regional visibility impairment.

Conversely, such participation can also

help provide a forum for tribal

participants to alert regional planning

organizations as to concerns on how

regional emissions are affecting air

quality in Indian country.

As noted in the preamble to the TAR,

we intend to work with tribes to identify

air quality priorities and needs, to build

communication and outreach to tribes

on air quality issues, and to provide

training to build tribes’ technical

capacity for implementing air quality

programs. We recognize, however, that

not all tribes will have the resources nor

the expertise to participate in regional

planning efforts for regional haze. An

important EPA role in regional planning

efforts will be to ensure that the overall

objectives of the regional haze program

are met where tribes are unable to

participate.

In order to encourage tribes to

develop self-sufficient programs, the

TAR provides tribes with the flexibility

of submitting programs as they are

developed, rather than in accordance

with statutory deadlines. This means

that tribes that choose to develop

programs, where necessary may take

additional time to submit

implementation plans for regional haze

over and above the deadlines in the

TEA–21 legislation as codified in

today’s final rule. (See unit III.B for a

discussion of these deadlines.) The

TEA–21 legislation changed the

deadlines for State submission of SIP

revisions to address regional haze,

which were originally set out in section

169B(e)(2) of the CAA. Section 49.4(f) of

the TAR provides that deadlines related

to SIP submittals under section

169(B)(e)(2) do not apply to tribes. We

encourage tribes choosing to develop

implementation plans to make every

effort to submit by the deadlines to

ensure that the plans are integrated with

and coordinated with regional planning

efforts. In the interim, EPA will work

with the States and tribes to ensure that

achievement of reasonable progress is

not delayed.

As noted previously in unit II of this

notice, sections 169A and 169B of the

CAA contain requirements for visibility

protection in Class I areas, and do not

require that States or tribes develop

plans and control strategies for visibility

protection for additional locations.

These provisions of the CAA do not

require implementation plans to address

regional haze in other Class I areas, such

as those designated as Class I by tribes

or States under section 164 of the CAA.

One commenter from a tribe expressed

concerns that the scenic beauty and

value of tribal areas should not be

viewed by EPA as less important than

the national parks and wilderness areas

that have ‘‘mandatory Class I’’ status.

While EPA believes that these tribal

areas are not afforded the same legal

protection under the CAA as Class I

areas, it is important for tribes to

understand that the regional haze

control program for the Federal areas

will help to protect scenic locations of

interest to tribes. For example, EPA

believes that modeling analyses aimed

at addressing Class I areas can readily

add receptor locations to analyze the

visibility improvements at selected

tribal locations. The EPA will work with

regional planning bodies to ensure that

tribal interests are represented and to

foster communication between States

and tribes, and we will encourage the

consideration of impacts on visibility in

tribal locations in regional planning

efforts.

VI. Miscellaneous Technical

Amendments to the Existing Rule

The rule includes the following

changes to coordinate the requirements

of today’s regional haze rule with the

1980 visibility regulations for

‘‘reasonably attributable’’ visibility

impairment:

Section 51.300. Purpose and

Applicability

We have amended this section to

clarify that subpart P includes

provisions for regional haze as well as

reasonably attributable visibility

impairment.

Section 51.301. Definitions

We have added the following terms:

reasonably attributable visibility

impairment, regional haze, deciview,

State, most-impaired days, leastimpaired days, implementation plan,

tribe, BART-eligible source, and

geographic enhancement. The other

definitions in this section apply to the

program for reasonably attributable

impairment as well as the new regional

haze program, except where it is noted

that they only apply to the program for

reasonably attributable impairment.

Section 51.302. Implementation Control

Strategies

We have changed references in

section 51.302(a) to the administrative

process requirements for public

hearings and SIP submissions, which

are now located in section 51.102 and

51.103. We have also amended this

section to clarify that the

implementation control strategies

addressed in the section apply to

reasonably attributable visibility

impairment.

Section 51.305. Monitoring

We have amended this section to

clarify that the monitoring requirements

in this section apply to reasonably

attributable visibility impairment.

VII. Administrative Requirements

In preparing any final rule, EPA must

meet the administrative requirements

contained in a number of statutes and

executive orders. In this section of the

preamble, we discuss how the final

regional haze rule addresses these

administrative requirements.

A. Regulatory Planning and Review by

the Office of Management and Budget

(OMB) (Executive Order 12866)

Under Executive Order 12866 (58 FR

51735, October 4, 1993,) the Agency
35760 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

must determine whether the regulatory

action is ‘‘significant’’ and, therefore,

subject to OMB review and the

requirements of the Executive Order.

The Order defines ‘‘significant

regulatory action’’ as one that is likely

to result in a rule that may:

(1) have an annual effect on the

economy of $100 million or more or

adversely affect in a material way the

economy, a sector of the economy,

productivity, competition, jobs, the

environment, public health or safety, or

State, local, or tribal governments or

communities;

(2) create a serious inconsistency or

otherwise interfere with an action taken

or planned by another agency;

(3) materially alter the budgetary

impacts of entitlements, grants, user

fees, or loan programs or the rights and

obligations of recipients thereof; or

(4) raise novel legal or policy issues

arising out of legal mandates, the

President’s priorities, or the principles

set forth in the Executive Order.

Pursuant to the terms of Executive

Order 12866, it has been determined

that this rule is a ‘‘significant regulatory

action’’ and EPA has submitted it to

OMB for review. The drafts of rules

submitted to OMB, the documents

accompanying such drafts, written

comments thereon, written responses by

EPA, and identification of the changes

made in response to OMB suggestions or

recommendations are available for

public inspection at EPA’s Air and

Radiation Docket Information Center

(Docket No. A–95–38).

The EPA has prepared and entered

into the docket a Regulatory Impact

Analysis (RIA) entitled Regulatory

Impact Analysis for the Regional Haze

Rule. This RIA assesses the costs,

economic impacts, and benefits for four

illustrative progress goals, two sets of

control strategies, two sets of

assumptions for estimating benefits, and

systems of national uniform versus

regionally varying progress goals. The

RIA is a caveated and illustrative

assessment of the potential

consequences of the regional haze rule

in 2015, a year near the end of the first

long-term progress period, 2018. As a

result of comments from the public as

well as changes initiated by EPA staff,

the RIA has a broader scope, improved

data, and more realistic modeling than

the analysis issued with the proposed

rule.

Despite these improvements, the RIA

is not a precise reflection of the actual

costs, economic impacts, and benefits

associated with the progress goals and

emission management strategies

developed as a result of the final

regional haze rule. This is due to the

fact that under the regional haze rule,

the States bear the primary

responsibility for establishing

reasonable progress goals as well as

emission management strategies for

meeting these goals. Until such time as

the States make those decisions, EPA

can only speculate as to which goals

may be established and what types of

control requirements or emission limits

might result from the associated

emission management strategies.

According to the RIA, there is

substantial visibility improvement due

to emissions from other CAA programs

such as those for the new O3 and PM

NAAQS and the Tier 2 mobile sources

rule. With illustrative goals ranging

from 1.0 deciview improvement in 15

years to 10 percent deciview

improvement in 10 years, the RIA finds

that between 22 and 52 percent of the

Class I area counties in the continental

U.S. achieve or surpass the progress

goals due to emissions reductions from

other CAA programs. Furthermore, by

looking at only partial attainment of the

PM and O3 NAAQS and a modest

(relative to the proposed rule) Tier 2

program, the RIA understated the

visibility improvements from these and

other CAA programs. Hence, if States

established reasonable progress goals

equivalent to the amount of visibility

improvement which could be achieved

by other CAA programs, the incremental

control costs of the regional haze rule

may be less than the costs estimated in

the RIA, as noted below, for the first

long-term strategy period. Under these

conditions there could be costs

associated with the planning, analysis,

and BART control elements of the rule.

Incremental annualized costs for those

elements are estimated to be $72 million

(1990 dollars).

However, if States all choose to

establish the same illustrative progress

goal, the RIA estimates incremental

control costs ranging from $1 to $4

billion with associated benefits ranging

from $1 billion to $19 billion. But,

visibility is not the only monetized

effects category. Many of the benefits

which could be monetized are

associated with improvements to human

health and other welfare effects. This is

because the emission control strategies

targeted at improving visibility in Class

I areas also generate air quality

improvements in many other parts of

the country. However, the estimated

visibility benefits which are monetized

are substantial, ranging, for example,

from 86 to 111 percent of control costs

for the 1 deciview improvement in 15

years illustrative progress goal and from

32 to 52 percent for the 10 percent

deciview improvement in 10 years

illustrative progress goal.

The RIA finds that the estimated net

benefits (benefits minus costs) may

increase and the potential for adverse

economic impact would decrease if

States exercise their discretion to

establish State or region-specific

reasonable visibility progress goals and

emission-management strategies.

According to the RIA simulations, not

all Class I areas achieve or surpass the

illustrative visibility progress goals even

after the simulation of two sets of

control strategies. But, the visibility

improvement is substantial with 84 to

94 percent of the 121 counties with 147

Class I areas in the continental U.S.

achieving the 1.0 deciview in 15 years

goal and 31 to 43 percent of the areas

achieving 10 percent deciview

improvement in 10 years goal.

Furthermore, all areas have improved

visibility. How much of the estimated

progress shortfall is due to the failure of

the RIA to fully account for the visibility

progress due to other CAA programs

and advances in control technology is

unknown.

The RIA, although highly caveated

and illustrative, represents an

improvement over the analysis prepared

for the proposed rule. Furthermore, the

RIA demonstrates significant visibility

progress in 121 counties with 147 Class

I areas in the continental U.S. These

improvements result from other CAA

programs as well as those targeted at the

illustrative progress goals. Despite

incomplete coverage of effects and

pollutants, the monetized benefits of

strategies associated with illustrative

nationally uniform goals are substantial,

outweighing the control strategy costs

under most conditions for the first longterm strategy period. However, higher

net benefits may result and the potential

for significant adverse impact may be

mitigated if States exercise the

discretion to establish reasonable

progress goals and emission

management strategies. The flexibility

for State discretion is, of course, exactly

what the regional haze rule provides.

B. Regulatory Flexibility Act

The EPA has determined that it is not

necessary to prepare a regulatory

flexibility analysis in connection with

this final rule. The EPA has also

determined that this rule will not have

a significant impact on a substantial

number of small entities because the

rule does not establish requirements

applicable to small entities.

The Regulatory Flexibility Act (5

U.S.C. §§ 601 et seq.) (RFA), as amended

by the Small Business Regulatory

Enforcement Fairness Act (Pub. L.
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35761

No.104–121) ( SBREFA), provides that

whenever an agency is required to

publish a general notice of proposed

rulemaking, it must prepare and make

available an initial regulatory flexibility

analysis, unless it certifies that the

proposed rule, if promulgated, will not

have ‘‘a significant economic impact on

a substantial number of small entities.’’

5 U.S.C. § 605(b). Courts have

interpreted the RFA to require a

regulatory flexibility analysis only when

small entities will be subject to the

requirements of the rule. See Motor and

Equip. Mfrs. Ass’n v. Nichols, 142 F.3d

449 (D.C. Cir. 1998); United Distribution

Cos. v. FERC, 88 F.3d 1105, 1170 (D.C.

Cir. 1996); Mid-Tex Elec. Co-op, Inc. v.

FERC, 773 F.2d 327, 342 (D.C. Cir. 1985)

(agency’s certification need only

consider the rule’s impact on entities

subject to the rule).

As stated in the proposal, the regional

haze rule will not establish

requirements applicable to small

entities. The rule applies to States, not

to small entities. The rule requires

States to develop, adopt, and submit SIP

revisions that will ensure reasonable

progress toward the national visibility

goal, and would generally leave to the

States the task of determining how to

obtain those reductions, including

which entities to regulate. In developing

emission control measures, section

169A of the CAA requires States to

address BART for a select list of major

stationary sources defined by section

169A(g)(7) of the CAA. As noted in the

proposal, however, the State’s

determination of BART for regional haze

involves some State discretion in

considering a number of factors set forth

in section 169A(g)(2), including the

costs of compliance. Further, the final

rule allows States to adopt alternative

measures in lieu of requiring the

installation and operation of BART at

these major stationary sources. As a

result, the potential consequences of

today’s final rule at specific sources are

speculative. Any requirements for

emission control measures, including

any requirements for BART, will be

established by State rulemakings. The

States will accordingly exercise

substantial intervening discretion in

implementing the final rule.

For the final rule, EPA is confirming

its initial certification that the rule

would not have a significant impact on

a substantial number of small entities.

The EPA notes, however, that the

Agency did conduct a more general

analysis of the potential impact on small

entities of possible State

implementation strategies. This analysis

is documented in the RIA. In addition,

as noted in the proposal, EPA undertook

small-entity outreach activities on a

voluntary basis. The EPA also has

issued guidance, entitled ‘‘Guidance on

Mitigation of Impact to Small Business

While Implementing Air Quality

Standards and Regulations,’’ which can

be found on the internet at: http://

ttnwww.rtpnc.epa.gov/implement/

actions.htmιOther. This guidance

outlines potential implementation

strategies that would mitigate impacts

on small sources and encourages States

to make use of these strategies wherever

possible and appropriate. The EPA did

receive comments regarding the impact

on the regional haze rule on small

entities. These comments are addressed

in the Response to Comments

document.

C. Paperwork Reduction Act—Impact on

Reporting Requirements

The information collection

requirements in this rule relating to

State requirements for the protection of

visibility in Class I national parks and

wilderness areas were submitted to

OMB for review and approval under the

Paperwork Reduction Act, 44 U.S.C.

3501, et seq. An Information Collection

Request document was prepared by EPA

(ICR No. 1813.02) and a copy may be

obtained from Sandy Farmer, by mail at

OPPE Regulatory Information Division,

U.S. EPA (2137) 401 M Street, S.W.;

Washington, DC 20460, by email at

farmer.sandy@epamail.epa.gov, or by

calling (202) 260–2740. A copy may also

be downloaded off the internet at http:/

/www.epa.gov/icr. The information

requirements are not effective until

OMB approves them.

This collection of information has an

estimated reporting burden, for the fifty

States and District of Columbia, of

approximately 22,000 to 47,000 hours

for a 3-year period between mid-1999

and mid-2002. The Agency expects the

Federal burden will be approximately

1900 to 4000 hours for the 3-year

period. The Agency anticipates States

costs of about $980,000 to $2,064,000

for the 3-year period. The Agency

estimates the annual Federal costs to be

approximately $83,000 to $175,000 for

the 3-year period. These estimates

include time for reviewing requirements

and instructions, evaluating data

sources, gathering and maintaining data,

and completing and reviewing the

collection of information.

Burden means the total time, effort, or

financial resources expended by persons

to generate, maintain, retain, or disclose

or provide information to or for a

Federal agency. This includes the time

needed to review instructions; develop,

acquire, install, and utilize technology

and systems for the purposes of

collecting, validating, and verifying

information, processing and

maintaining information, and disclosing

and providing information; adjust the

existing ways to comply with any

previously applicable instructions and

requirements; train personnel to be able

to respond to a collection of

information; search data sources;

complete and review the collection of

information; and transmit or otherwise

disclose the information.

An agency may not conduct or

sponsor, and a person is not required to

respond to a collection of information

unless it displays a currently valid OMB

control number. The OMB control

numbers for EPA’s regulations are listed

in 40 CFR Part 9 and 48 CFR Chapter

15.

D. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates

Reform Act of 1995 (Pub. L. 104–4)

(UMRA), establishes requirements for

Federal agencies to assess the effects of

their regulatory actions on State, local,

and tribal governments and the private

sector. Under section 202 of the UMRA,

2 U.S.C. 1532, EPA generally must

prepare a written statement, including a

cost-benefit analysis, for any proposed

or final rule that ‘‘includes any Federal

mandate that may result in the

expenditure by State, local, and tribal

governments, in the aggregate, or by the

private sector, of $100,000,000 or more

* * * in any one year.’’ A ‘‘Federal

mandate’’ is defined under section

421(6), 2 U.S.C. 658(6), to include a

‘‘Federal intergovernmental mandate’’

and a ‘‘Federal private sector mandate.’’

A ‘‘Federal intergovernmental

mandate,’’ in turn, is defined to include

a regulation that ‘‘would impose an

enforceable duty upon State, local, or

tribal governments,’’ section

421(5)(A)(i), 2 U.S.C. 658(5)(A)(i),

except for, among other things, a duty

that is ‘‘a condition of Federal

assistance,’’ section 421(5)(A)(i)(I). A

‘‘Federal private sector mandate’’

includes a regulation that ‘‘would

impose an enforceable duty upon the

private sector,’’ with certain exceptions,

section 421(7)(A), 2 U.S.C. 658(7)(A).

Before promulgating an EPA rule for

which a written statement is needed

under section 202 of the UMRA, section

205, 2 U.S.C. 1535, of the UMRA

generally requires EPA to identify and

consider a reasonable number of

regulatory alternatives and adopt the

least costly, most cost effective, or least

burdensome alternative that achieves

the objectives of the rule.

The RIA prepared by EPA and placed

in the docket for this rulemaking is

consistent with the requirements of
35762 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

section 202 of the UMRA. Furthermore,

EPA is not directly establishing any

regulatory requirements that may

significantly or uniquely affect small

governments, including tribal

governments. Thus, EPA is not obligated

to develop under section 203 of the

UMRA a small government agency plan.

Further, as described in the proposal,

EPA carried out consultations with the

governmental entities affected by this

rule in a manner consistent with the

intergovernmental consultation

provisions of section 204 of the UMRA.

The EPA also believes that because

the rule provides States with substantial

flexibility, the proposed rule meets the

UMRA requirement in section 205 to

select the least costly and burdensome

alternative in light of the statutory

mandate to issue regulations that make

reasonable progress toward the national

visibility protection goal. The rule

provides States with the flexibility to

establish reasonable progress goals and

BART based on certain criteria, one of

which is the costs of compliance. The

rule also provides States with the

flexibility to adopt alternatives, such as

an emissions trading program, in lieu of

requiring BART. Finally, the rule

provides the States with the flexibility

to develop long-term strategies. The

regional haze rule, therefore, inherently

provides for adoption of the least costly,

most cost effective, or least burdensome

alternative that achieves the objective of

the rule.

The EPA is not reaching a final

conclusion as to the applicability of the

requirements of UMRA to this

rulemaking action. It is questionable

whether a requirement to submit a SIP

revision constitutes a Federal mandate.

The obligation for a state to revise its

SIP that arises out of sections 110(a),

169A and 169B of the CAA is not legally

enforceable by a court of law and, at

most, is a condition for continued

receipt of highway funds. Therefore, it

is possible to view an action requiring

such a submittal as not creating any

enforceable duty within the meaning of

section 421(5)(A)(i) of UMRA (2 U.S.C.

658(5)(A)(i)). Even if it did, the duty

could be viewed as falling within the

exception for a condition of Federal

assistance under section 421(5)(A)(i)(I)

of UMRA (2 U.S.C. 658(5)(A)(i)(I)). As

noted earlier, however, notwithstanding

these issues, the discussion in section 2

and the analysis in Chapter 8 of the RIA

constitutes the UMRA statement that

would be required by UMRA if its

statutory provisions applied, and EPA

has consulted with governmental

entities as would be required by UMRA.

Consequently, it is not necessary for

EPA to reach a conclusion as to the

applicability of the UMRA

requirements.

E. Environmental Justice—Executive

Order 12898

Executive Order 12898 requires that

each Federal agency make achieving

environmental justice part of its mission

by identifying and addressing, as

appropriate, disproportionately high

and adverse human health or

environmental effects of its programs,

policies, and activities on minorities

and low-income populations. The

requirements of Executive Order 12898

have been addressed to the extent

practicable in the RIA cited above,

particularly in chapters 2 and 9 of the

RIA.

F. Congressional Review Act

The Congressional Review Act, 5

U.S.C. 801 et seq., as added by the Small

Business Regulatory Enforcement

Fairness Act of 1996, generally provides

that before a rule may take effect, the

agency promulgating the rule must

submit a rule report, which includes a

copy of the rule, to each House of the

Congress and to the Comptroller General

of the U.S. The EPA will submit a report

containing this rule and other required

information to the U.S. Senate, the U.S.

House of Representatives, and the

Comptroller General of the U.S. prior to

publication of the rule in the Federal

Register. A ‘‘major rule’’ cannot take

effect until 60 days after it is published

in the Federal Register. This action is a

‘‘major rule’’ as defined by 5 U.S.C.

section 804(2). This rule will be

effective August 30, 1999.

G. Protection of Children From

Environmental Health Risks and Safety

Risks—Executive Order 13045

Executive Order 13045: ‘‘Protection of

Children from Environmental Health

Risks and Safety Risks’’ (62 FR 19885,

April 23, 1997) applies to any rule that:

(1) is determined to be ‘‘economically

significant’’ as defined under E.O.

12866, and (2) concerns an

environmental health or safety risk that

EPA has reason to believe may have a

disproportionate effect on children. If

the regulatory action meets both criteria,

the Agency must evaluate the

environmental health or safety effects of

the planned rule on children, and

explain why the planned regulation is

preferable to other potentially effective

and reasonably feasible alternatives

considered by the Agency. The EPA

interprets E.O. 13045 as applying only

to those regulatory actions that are

based on health or safety risks, such that

the analysis required under section 5–

501 of the Order has the potential to

influence the regulation. The regional

haze rule is not subject to E.O. 13045

because it does not establish an

environmental standard intended to

mitigate health or safety risks.

H. Enhancing the Intergovernmental

Partnership—Executive Order 12875

Under Executive Order 12875, EPA

may not issue a regulation that is not

required by statute and that creates a

mandate upon a State, local or tribal

government, unless the Federal

government provides the funds

necessary to pay the direct compliance

costs incurred by those governments, or

EPA consults with those governments. If

EPA complies by consulting, Executive

Order 12875 requires EPA to provide to

the OMB a description of the extent of

EPA’s prior consultation with

representatives of affected State, local

and tribal governments, the nature of

their concerns, copies of any written

communications from the governments,

and a statement supporting the need to

issue the regulation. In addition,

Executive Order 12875 requires EPA to

develop an effective process permitting

elected officials and other

representatives of State, local and tribal

governments ‘‘to provide meaningful

and timely input in the development of

regulatory proposals containing

significant unfunded mandates.’’

Today’s final rule does not create a

mandate on State, local or tribal

governments. As explained in the

discussion of UMRA (unit VII.D), this

rule does not impose an enforceable

duty on these entities. Accordingly, the

requirements of section 1(a) of

Executive Order 12875 do not apply to

this rule.

The EPA notes, however that

considerable consultation has taken

place with State, local and tribal

government representatives in

developing the final regional haze rule.

In September 1995, EPA formed a

subcommittee under the authority of the

Federal Advisory Committee Act to

advise the Agency on various issues

related to implementation of the revised

ozone and particulate matter NAAQS

and the regional haze program. This

group met a total of 13 times between

September 1995 and completion of its

duties in December 1997. Several State

and local governmental representatives

were on this subcommittee. The EPA

received and reviewed comments from

over 40 States and 1 tribal government

on the July 1997 proposal. Tribes in the

west have been active in discussion on

regional haze, both as members of the

GCVTC, and in the follow-on body, the

WRAP. In addition, EPA has held
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35763

numerous meetings with State and local

representatives.

I. Executive Order 13084: Consultation

and Coordination With Indian Tribal

Governments

Under Executive Order 13084, EPA

may not issue a regulation that is not

required by statute, that significantly or

uniquely affects the communities of

Indian tribal governments, and that

imposes substantial direct compliance

costs on those communities, unless the

Federal government provides the funds

necessary to pay the direct compliance

costs incurred by the tribal

governments, or EPA consults with

those governments. If EPA complies by

consulting, Executive Order 13084

requires EPA to provide to OMB, in a

separately identified section of the

preamble to the rule, a description of

the extent of EPA’s prior consultation

with representatives of affected tribal

governments, a summary of the nature

of their concerns, and a statement

supporting the need to issue the

regulation. In addition, Executive Order

13084 requires EPA to develop an

effective process permitting elected

officials and other representatives of

Indian tribal governments ‘‘to provide

meaningful and timely input in the

development of regulatory policies on

matters that significantly or uniquely

affect their communities.’’

Because the rule does not establish a

visibility progress goal or emission

management strategy, the rule does not

impose control or other direct

compliance requirements. Hence, the

rule does not create a mandate on tribal

governments. Accordingly, the

requirements of 3(b) of Executive Order

13084 do not apply to this rule.

J. National Technology Transfer and

Advancement Act

Section 12(d) of the National

Technology Transfer and Advancement

Act of 1995 (‘‘NTTAA’’), Pub. L. No.

104–113, section 12(d) (15 U.S.C. 272

note) directs EPA to use voluntary

consensus standards in its regulatory

activities unless to do so would be

inconsistent with applicable law or

otherwise impractical. Voluntary

consensus standards are technical

standards (e.g., materials specifications,

test methods, sampling procedures, and

business practices) that are developed or

adopted by voluntary consensus

standards bodies. The NTTAA directs

EPA to provide Congress, through OMB,

explanations when the Agency decides

not to use available and applicable

voluntary consensus standards.

This action does not involve technical

standards. Therefore, EPA did not

consider the use of any voluntary

consensus standards.

List of Subjects in 40 CFR Part 51

Environmental protection,

Administrative practice and procedure,

Air pollution control, Carbon monoxide,

Nitrogen dioxide, Particulate matter,

Sulfur oxides, Volatile organic

compounds.

Dated: April 22, 1999.

Carol M. Browner,

Administrator.

For the reasons set forth in the

preamble, part 51 of chapter I of title 40

of the Code of Federal Regulations is

amended as follows:

PART 51—REQUIREMENTS FOR

PREPARATION, ADOPTION, AND

SUBMITTAL OF IMPLEMENTATION

PLANS

1. The authority citation for Part 51 is

revised to read as follows:

Authority: 42 U.S.C. 7410, 7414, 7421,

7470–7479, 7491, 7492, 7601, and 7602.

Subpart P—Protection of Visibility

2. Section 51.300 is amended by

revising paragraphs (a), (b)(1)

introductory text, and (b)(2), and by

adding paragraph (b)(3) to read as

follows:

§ 51.300 Purpose and applicability.

(a) Purpose. The primary purposes of

this subpart are to require States to

develop programs to assure reasonable

progress toward meeting the national

goal of preventing any future, and

remedying any existing, impairment of

visibility in mandatory Class I Federal

areas which impairment results from

manmade air pollution; and to establish

necessary additional procedures for new

source permit applicants, States and

Federal Land Managers to use in

conducting the visibility impact

analysis required for new sources under

§ 51.166. This subpart sets forth

requirements addressing visibility

impairment in its two principal forms:

‘‘reasonably attributable’’ impairment

(i.e., impairment attributable to a single

source/small group of sources) and

regional haze (i.e., widespread haze

from a multitude of sources which

impairs visibility in every direction over

a large area).

(b) Applicability. (1) General

Applicability. The provisions of this

subpart pertaining to implementation

plan requirements for assuring

reasonable progress in preventing any

future and remedying any existing

visibility impairment are applicable to:

* * * * *

(2) The provisions of this subpart

pertaining to implementation plans to

address reasonably attributable visibility

impairment are applicable to the

following States:

Alabama, Alaska, Arizona, Arkansas,

California, Colorado, Florida, Georgia,

Hawaii, Idaho, Kentucky, Louisiana,

Maine, Michigan, Minnesota, Missouri,

Montana, Nevada, New Hampshire, New

Jersey, New Mexico, North Carolina, North

Dakota, Oklahoma, Oregon, South

Carolina, South Dakota, Tennessee, Texas,

Utah, Vermont, Virginia, Virgin Islands,

Washington, West Virginia, Wyoming.

(3) The provisions of this subpart

pertaining to implementation plans to

address regional haze visibility

impairment are applicable to all States

as defined in section 302(d) of the Clean

Air Act (CAA) except Guam, Puerto

Rico, American Samoa, and the

Northern Mariana Islands.

BILLING CODE 6560–50–U

3. Section 51.301 is amended by

removing the paragraph designations,

placing the defined terms in

alphabetical order, revising the

definitions of Federal Land Manager,

Major stationary source, Natural

conditions, and Visibility impairment,

and adding in alphabetical order

definitions of Reasonably attributable

visibility impairment, Regional haze,

Deciview, State, Most impaired days,

Least impaired days, Implementation

plan, Indian tribe or tribe, BART-eligible

source, and Geographic enhancement

for the purpose of § 51.308 to read as

follows:

§ 51.301 Definitions.

* * * * *

BART-eligible source means an

existing stationary facility as defined in

this section.

* * * * *

Deciview means a measurement of

visibility impairment. A deciview is a

haze index derived from calculated light

extinction, such that uniform changes in

haziness correspond to uniform

incremental changes in perception

across the entire range of conditions,

from pristine to highly impaired. The

deciview haze index is calculated based

on the following equation (for the

purposes of calculating deciview, the

atmospheric light extinction coefficient

must be calculated from aerosol

measurements):

Deciview haze index=10 lne (bext/10

Mm¥1).

Where bext=the atmospheric light

extinction coefficient, expressed in

inverse megameters (Mm¥1).

* * * * *
35764 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

Federal Land Manager means the

Secretary of the department with

authority over the Federal Class I area

(or the Secretary’s designee) or, with

respect to Roosevelt-Campobello

International Park, the Chairman of the

Roosevelt-Campobello International

Park Commission.

* * * * *

Geographic enhancement for the

purpose of § 51.308 means a method,

procedure, or process to allow a broad

regional strategy, such as an emissions

trading program designed to achieve

greater reasonable progress than BART

for regional haze, to accommodate

BART for reasonably attributable

impairment.

Implementation plan means, for the

purposes of this part, any State

Implementation Plan, Federal

Implementation Plan, or Tribal

Implementation Plan.

* * * * *

Indian tribe or tribe means any Indian

tribe, band, nation, or other organized

group or community, including any

Alaska Native village, which is federally

recognized as eligible for the special

programs and services provided by the

United States to Indians because of their

status as Indians.

* * * * *

Least impaired days means the

average visibility impairment (measured

in deciviews) for the twenty percent of

monitored days in a calendar year with

the lowest amount of visibility

impairment.

Major stationary source and major

modification mean major stationary

source and major modification,

respectively, as defined in § 51.166.

* * * * *

Most impaired days means the

average visibility impairment (measured

in deciviews) for the twenty percent of

monitored days in a calendar year with

the highest amount of visibility

impairment.

Natural conditions includes naturally

occurring phenomena that reduce

visibility as measured in terms of light

extinction, visual range, contrast, or

coloration.

* * * * *

Reasonably attributable visibility

impairment means visibility impairment

that is caused by the emission of air

pollutants from one, or a small number

of sources.

* * * * *

Regional haze means visibility

impairment that is caused by the

emission of air pollutants from

numerous sources located over a wide

geographic area. Such sources include,

but are not limited to, major and minor

stationary sources, mobile sources, and

area sources.

* * * * *

State means ‘‘State’’ as defined in

section 302(d) of the CAA.

* * * * *

Visibility impairment means any

humanly perceptible change in visibility

(light extinction, visual range, contrast,

coloration) from that which would have

existed under natural conditions.

* * * * *

BILLING CODE 6560–50–M

4. Section 51.302 is amended by

revising the section heading, paragraphs

(a), (c) introductory text, (c)(1), (c)(2)

introductory text, (c)(4) introductory

text, and (c)(4)(iv) to read as follows:

§ 51.302 Implementation control strategies

for reasonably attributable visibility

impairment.

(a) Plan Revision Procedures. (1) Each

State identified in § 51.300(b)(2) must

have submitted, not later than

September 2, 1981, an implementation

plan meeting the requirements of this

subpart pertaining to reasonably

attributable visibility impairment.

(2)(i) The State, prior to adoption of

any implementation plan to address

reasonably attributable visibility

impairment required by this subpart,

must conduct one or more public

hearings on such plan in accordance

with § 51.102.

(ii) In addition to the requirements in

§ 51.102, the State must provide written

notification of such hearings to each

affected Federal Land Manager, and

other affected States, and must state

where the public can inspect a summary

prepared by the Federal Land Managers

of their conclusions and

recommendations, if any, on the

proposed plan revision.

(3) Submission of plans as required by

this subpart must be conducted in

accordance with the procedures in

§ 51.103.

* * * * *

(c) General plan requirements for

reasonably attributable visibility

impairment. (1) The affected Federal

Land Manager may certify to the State,

at any time, that there exists reasonably

attributable impairment of visibility in

any mandatory Class I Federal area.

(2) The plan must contain the

following to address reasonably

attributable impairment:

* * * * *

(4) For any existing reasonably

attributable visibility impairment the

Federal Land Manager certifies to the

State under paragraph (c)(1) of this

section, at least 6 months prior to plan

submission or revision:

* * * * *

(iv) The plan must require that each

existing stationary facility required to

install and operate BART do so as

expeditiously as practicable but in no

case later than five years after plan

approval.

* * * * *

5. Section 51.305 is amended by

revising the section heading and

paragraph (a) to read as follows:

§ 51.305 Monitoring for reasonably

attributable visibility impairment.

(a) For the purposes of addressing

reasonably attributable visibility

impairment, each State containing a

mandatory Class I Federal area must

include in the plan a strategy for

evaluating reasonably attributable

visibility impairment in any mandatory

Class I Federal area by visual

observation or other appropriate

monitoring techniques. Such strategy

must take into account current and

anticipated visibility monitoring

research, the availability of appropriate

monitoring techniques, and such

guidance as is provided by the Agency.

* * * * *

6. Section 51.306 is amended by

revising the section heading, paragraph

(a)(1), paragraph (c) introductory text,

and paragraph (d) to read as follows:

§ 51.306 Long-term strategy requirements

for reasonably attributable visibility

impairment.

(a)(1) For the purposes of addressing

reasonably attributable visibility

impairment, each plan must include a

long-term (10–15 years) strategy for

making reasonable progress toward the

national goal specified in § 51.300(a).

This strategy must cover any existing

impairment the Federal Land Manager

certifies to the State at least 6 months

prior to plan submission, and any

integral vista of which the Federal Land

Manager notifies the State at least 6

months prior to plan submission.

* * * * *

(c) The plan must provide for periodic

review and revision, as appropriate, of

the long-term strategy for addressing

reasonably attributable visibility

impairment. The plan must provide for

such periodic review and revision not

less frequently than every 3 years until

the date of submission of the State’s first

plan addressing regional haze visibility

impairment in accordance with

§ 51.308(b) and (c). On or before this

date, the State must revise its plan to

provide for review and revision of a

coordinated long-term strategy for

addressing reasonably attributable and
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35765

regional haze visibility impairment, and

the State must submit the first such

coordinated long-term strategy. Future

coordinated long-term strategies must be

submitted consistent with the schedule

for periodic progress reports set forth in

§ 51.308(g). Until the State revises its

plan to meet this requirement, the State

must continue to comply with existing

requirements for plan review and

revision, and with all emission

management requirements in the plan to

address reasonably attributable

impairment. This requirement does not

affect any preexisting deadlines for State

submittal of a long-term strategy review

(or element thereof) between August 30,

1999, and the date required for

submission of the State’s first regional

haze plan. In addition, the plan must

provide for review of the long-term

strategy as it applies to reasonably

attributable impairment, and revision as

appropriate, within 3 years of State

receipt of any certification of reasonably

attributable impairment from a Federal

Land Manager. The review process must

include consultation with the

appropriate Federal Land Managers, and

the State must provide a report to the

public and the Administrator on

progress toward the national goal. This

report must include an assessment of:

* * * * *

(d) The long-term strategy must

provide for review of the impacts from

any new major stationary source or

major modifications on visibility in any

mandatory Class I Federal area. This

review of major stationary sources or

major modifications must be in

accordance with § 51.307, § 51.166,

§ 51.160, and any other binding

guidance provided by the Agency

insofar as these provisions pertain to

protection of visibility in any mandatory

Class I Federal areas.

* * * * *

7. Section 51.307 is amended by

revising paragraph (a) introductory text,

(a)(2) and (c) to read as follows:

§ 51.307 New source review.

(a) For purposes of new source review

of any new major stationary source or

major modification that would be

constructed in an area that is designated

attainment or unclassified under section

107(d)(1)(D) or (E) of the CAA, the State

plan must, in any review under § 51.166

with respect to visibility protection and

analyses, provide for:

* * * * *

(2) Where the State requires or

receives advance notification (e.g. early

consultation with the source prior to

submission of the application or

notification of intent to monitor under

§ 51.166) of a permit application of a

source that may affect visibility the

State must notify all affected Federal

Land Managers within 30 days of such

advance notification, and

* * * * *

(c) Review of any major stationary

source or major modification under

paragraph (b) of this section, shall be

conducted in accordance with

paragraph (a) of this section, and

§ 51.166(o), (p)(1) through (2), and (q).

In conducting such reviews the State

must ensure that the source’s emissions

will be consistent with making

reasonable progress toward the national

visibility goal referred to in § 51.300(a).

The State may take into account the

costs of compliance, the time necessary

for compliance, the energy and nonair

quality environmental impacts of

compliance, and the useful life of the

source.

* * * * *

8. A new § 51.308 is added to subpart

P to read as follows:

§ 51.308 Regional haze program

requirements.

(a) What is the purpose of this

section? This section establishes

requirements for implementation plans,

plan revisions, and periodic progress

reviews to address regional haze.

(b) When are the first implementation

plans due under the regional haze

program? Except as provided in

paragraph (c) of this section and

§ 51.309(c), each State identified in

§ 51.300(b)(3) must submit an

implementation plan for regional haze

meeting the requirements of paragraphs

(d) and (e) of this section by the

following dates:

(1) For any area designated as

attainment or unclassifiable for the

national ambient air quality standard

(NAAQS) for fine particulate matter

(PM2.5), the State must submit a regional

haze implementation plan to EPA

within 12 months after the date of

designation.

(2) For any area designated as

nonattainment for the PM2.5 NAAQS,

the State must submit a regional haze

implementation plan to EPA at the same

time that the State’s plan for

implementation of the PM2.5 NAAQS

must be submitted under section 172 of

the CAA, that is, within 3 years after the

area is designated as nonattainment, but

not later than December 31, 2008.

(c) Options for regional planning. If at

the time the SIP for regional haze would

otherwise be due, a State is working

with other States to develop a

coordinated approach to regional haze

by participating in a regional planning

process, the State may choose to defer

addressing the core requirements for

regional haze in paragraph (d) of this

section and the requirements for BART

in paragraph (e) of this section. If a State

opts to do this, it must meet the

following requirements:

(1) The State must submit an

implementation plan by the earliest date

by which an implementation plan

would be due for any area of the State

under paragraph (b) of this section. This

implementation plan must contain the

following:

(i) A demonstration of ongoing

participation in a regional planning

process to address regional haze, and an

agreement by the State to continue

participating with one or more other

States in such a process for the

development of this and future

implementation plan revisions;

(ii) A showing, based on available

inventory, monitoring, or modeling

information, that emissions from within

the State contribute to visibility

impairment in a mandatory Class I

Federal Area outside the State, or that

emissions from another State contribute

to visibility impairment in any

mandatory Class I Federal area within

the State.

(iii) A description of the regional

planning process, including a list of the

States which have agreed to work

together to address regional haze in a

region (i.e., the regional planning

group), the goals, objectives,

management, and decisionmaking

structure of the regional planning group,

deadlines for completing significant

technical analyses and developing

emission management strategies, and a

schedule for State review and adoption

of regulations implementing the

recommendations of the regional group;

(iv) A commitment by the State to

submit an implementation plan revision

addressing the requirements in

paragraphs (d) and (e) of this section by

the date specified in paragraph (c)(2) of

this section. In addition, the State must

commit to develop its plan revision in

coordination with the other States

participating in the regional planning

process, and to fully address the

recommendations of the regional

planning group.

(v) A list of all BART-eligible sources

within the State.

(2) The State must submit an

implementation plan revision

addressing the requirements in

paragraphs (d) and (e) of this section by

the latest date an area within the

planning region would be required to

submit an implementation plan under

paragraph (b) of this section, but in any

event, no later than December 31, 2008.
35766 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

(d) What are the core requirements for

the implementation plan for regional

haze? The State must address regional

haze in each mandatory Class I Federal

area located within the State and in

each mandatory Class I Federal area

located outside the State which may be

affected by emissions from within the

State. To meet the core requirements for

regional haze for these areas, the State

must submit an implementation plan

containing the following plan elements

and supporting documentation for all

required analyses:

(1) Reasonable progress goals. For

each mandatory Class I Federal area

located within the State, the State must

establish goals (expressed in deciviews)

that provide for reasonable progress

towards achieving natural visibility

conditions. The reasonable progress

goals must provide for an improvement

in visibility for the most impaired days

over the period of the implementation

plan and ensure no degradation in

visibility for the least impaired days

over the same period.

(i) In establishing a reasonable

progress goal for any mandatory Class I

Federal area within the State, the State

must:

(A) Consider the costs of compliance,

the time necessary for compliance, the

energy and non-air quality

environmental impacts of compliance,

and the remaining useful life of any

potentially affected sources, and include

a demonstration showing how these

factors were taken into consideration in

selecting the goal.

(B) Analyze and determine the rate of

progress needed to attain natural

visibility conditions by the year 2064.

To calculate this rate of progress, the

State must compare baseline visibility

conditions to natural visibility

conditions in the mandatory Federal

Class I area and determine the uniform

rate of visibility improvement

(measured in deciviews) that would

need to be maintained during each

implementation period in order to attain

natural visibility conditions by 2064. In

establishing the reasonable progress

goal, the State must consider the

uniform rate of improvement in

visibility and the emission reduction

measures needed to achieve it for the

period covered by the implementation

plan.

(ii) For the period of the

implementation plan, if the State

establishes a reasonable progress goal

that provides for a slower rate of

improvement in visibility than the rate

that would be needed to attain natural

conditions by 2064, the State must

demonstrate, based on the factors in

paragraph (d)(1)(i)(A) of this section,

that the rate of progress for the

implementation plan to attain natural

conditions by 2064 is not reasonable;

and that the progress goal adopted by

the State is reasonable. The State must

provide to the public for review as part

of its implementation plan an

assessment of the number of years it

would take to attain natural conditions

if visibility improvement continues at

the rate of progress selected by the State

as reasonable.

(iii) In determining whether the

State’s goal for visibility improvement

provides for reasonable progress

towards natural visibility conditions,

the Administrator will evaluate the

demonstrations developed by the State

pursuant to paragraphs (d)(1)(i) and

(d)(1)(ii) of this section.

(iv) In developing each reasonable

progress goal, the State must consult

with those States which may reasonably

be anticipated to cause or contribute to

visibility impairment in the mandatory

Class I Federal area. In any situation in

which the State cannot agree with

another such State or group of States

that a goal provides for reasonable

progress, the State must describe in its

submittal the actions taken to resolve

the disagreement. In reviewing the

State’s implementation plan submittal,

the Administrator will take this

information into account in determining

whether the State’s goal for visibility

improvement provides for reasonable

progress towards natural visibility

conditions.

(v) The reasonable progress goals

established by the State are not directly

enforceable but will be considered by

the Administrator in evaluating the

adequacy of the measures in the

implementation plan to achieve the

progress goal adopted by the State.

(vi) The State may not adopt a

reasonable progress goal that represents

less visibility improvement than is

expected to result from implementation

of other requirements of the CAA during

the applicable planning period.

(2) Calculations of baseline and

natural visibility conditions. For each

mandatory Class I Federal area located

within the State, the State must

determine the following visibility

conditions (expressed in deciviews):

(i) Baseline visibility conditions for

the most impaired and least impaired

days. The period for establishing

baseline visibility conditions is 2000 to

2004. Baseline visibility conditions

must be calculated, using available

monitoring data, by establishing the

average degree of visibility impairment

for the most and least impaired days for

each calendar year from 2000 to 2004.

The baseline visibility conditions are

the average of these annual values. For

mandatory Class I Federal areas without

onsite monitoring data for 2000–2004,

the State must establish baseline values

using the most representative available

monitoring data for 2000–2004, in

consultation with the Administrator or

his or her designee;

(ii) For an implementation plan that is

submitted by 2003, the period for

establishing baseline visibility

conditions for the period of the first

long-term strategy is the most recent 5-

year period for which visibility

monitoring data are available for the

mandatory Class I Federal areas

addressed by the plan. For mandatory

Class I Federal areas without onsite

monitoring data, the State must

establish baseline values using the most

representative available monitoring

data, in consultation with the

Administrator or his or her designee;

(iii) Natural visibility conditions for

the most impaired and least impaired

days. Natural visibility conditions must

be calculated by estimating the degree of

visibility impairment existing under

natural conditions for the most impaired

and least impaired days, based on

available monitoring information and

appropriate data analysis techniques;

and

(iv)(A) For the first implementation

plan addressing the requirements of

paragraphs (d) and (e) of this section,

the number of deciviews by which

baseline conditions exceed natural

visibility conditions for the most

impaired and least impaired days; or

(B) For all future implementation plan

revisions, the number of deciviews by

which current conditions, as calculated

under paragraph (f)(1) of this section,

exceed natural visibility conditions for

the most impaired and least impaired

days.

(3) Long-term strategy for regional

haze. Each State listed in § 51.300(b)(3)

must submit a long-term strategy that

addresses regional haze visibility

impairment for each mandatory Class I

Federal area within the State and for

each mandatory Class I Federal area

located outside the State which may be

affected by emissions from the State.

The long-term strategy must include

enforceable emissions limitations,

compliance schedules, and other

measures as necessary to achieve the

reasonable progress goals established by

States having mandatory Class I Federal

areas. In establishing its long-term

strategy for regional haze, the State must

meet the following requirements:

(i) Where the State has emissions that

are reasonably anticipated to contribute

to visibility impairment in any

mandatory Class I Federal area located
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35767

in another State or States, the State must

consult with the other State(s) in order

to develop coordinated emission

management strategies. The State must

consult with any other State having

emissions that are reasonably

anticipated to contribute to visibility

impairment in any mandatory Class I

Federal area within the State.

(ii) Where other States cause or

contribute to impairment in a

mandatory Class I Federal area, the State

must demonstrate that it has included in

its implementation plan all measures

necessary to obtain its share of the

emission reductions needed to meet the

progress goal for the area. If the State

has participated in a regional planning

process, the State must ensure it has

included all measures needed to achieve

its apportionment of emission reduction

obligations agreed upon through that

process.

(iii) The State must document the

technical basis, including modeling,

monitoring and emissions information,

on which the State is relying to

determine its apportionment of

emission reduction obligations

necessary for achieving reasonable

progress in each mandatory Class I

Federal area it affects. The State may

meet this requirement by relying on

technical analyses developed by the

regional planning organization and

approved by all State participants. The

State must identify the baseline

emissions inventory on which its

strategies are based. The baseline

emissions inventory year is presumed to

be the most recent year of the

consolidate periodic emissions

inventory.

(iv) The State must identify all

anthropogenic sources of visibility

impairment considered by the State in

developing its long-term strategy. The

State should consider major and minor

stationary sources, mobile sources, and

area sources.

(v) The State must consider, at a

minimum, the following factors in

developing its long-term strategy:

(A) Emission reductions due to

ongoing air pollution control programs,

including measures to address

reasonably attributable visibility

impairment;

(B) Measures to mitigate the impacts

of construction activities;

(C) Emissions limitations and

schedules for compliance to achieve the

reasonable progress goal;

(D) Source retirement and

replacement schedules;

(E) Smoke management techniques for

agricultural and forestry management

purposes including plans as currently

exist within the State for these

purposes;

(F) Enforceability of emissions

limitations and control measures; and

(G) The anticipated net effect on

visibility due to projected changes in

point, area, and mobile source

emissions over the period addressed by

the long-term strategy.

(4) Monitoring strategy and other

implementation plan requirements. The

State must submit with the

implementation plan a monitoring

strategy for measuring, characterizing,

and reporting of regional haze visibility

impairment that is representative of all

mandatory Class I Federal areas within

the State. This monitoring strategy must

be coordinated with the monitoring

strategy required in § 51.305 for

reasonably attributable visibility

impairment. Compliance with this

requirement may be met through

participation in the Interagency

Monitoring of Protected Visual

Environments network. The

implementation plan must also provide

for the following:

(i) The establishment of any

additional monitoring sites or

equipment needed to assess whether

reasonable progress goals to address

regional haze for all mandatory Class I

Federal areas within the State are being

achieved.

(ii) Procedures by which monitoring

data and other information are used in

determining the contribution of

emissions from within the State to

regional haze visibility impairment at

mandatory Class I Federal areas both

within and outside the State.

(iii) For a State with no mandatory

Class I Federal areas, procedures by

which monitoring data and other

information are used in determining the

contribution of emissions from within

the State to regional haze visibility

impairment at mandatory Class I

Federal areas in other States.

(iv) The implementation plan must

provide for the reporting of all visibility

monitoring data to the Administrator at

least annually for each mandatory Class

I Federal area in the State. To the extent

possible, the State should report

visibility monitoring data electronically.

(v) A statewide inventory of emissions

of pollutants that are reasonably

anticipated to cause or contribute to

visibility impairment in any mandatory

Class I Federal area. The inventory must

include emissions for a baseline year,

emissions for the most recent year for

which data are available, and estimates

of future projected emissions. The State

must also include a commitment to

update the inventory periodically.

(vi) Other elements, including

reporting, recordkeeping, and other

measures, necessary to assess and report

on visibility.

(e) Best Available Retrofit Technology

(BART) requirements for regional haze

visibility impairment. The State must

submit an implementation plan

containing emission limitations

representing BART and schedules for

compliance with BART for each BARTeligible source that may reasonably be

anticipated to cause or contribute to any

impairment of visibility in any

mandatory Class I Federal area, unless

the State demonstrates that an emissions

trading program or other alternative will

achieve greater reasonable progress

toward natural visibility conditions.

(1) To address the requirements for

BART, the State must submit an

implementation plan containing the

following plan elements and include

documentation for all required analyses:

(i) A list of all BART-eligible sources

within the State.

(ii) A determination of BART for each

BART-eligible source in the State that

emits any air pollutant which may

reasonably be anticipated to cause or

contribute to any impairment of

visibility in any mandatory Class I

Federal area. All such sources are

subject to BART. This determination

must be based on the following

analyses:

(A) An analysis of the best system of

continuous emission control technology

available and associated emission

reductions achievable for each BARTeligible source within the State subject

to BART. In this analysis, the State must

take into consideration the technology

available, the costs of compliance, the

energy and nonair quality

environmental impacts of compliance,

any pollution control equipment in use

at the source, and the remaining useful

life of the source; and

(B) An analysis of the degree of

visibility improvement that would be

achieved in each mandatory Class I

Federal area as a result of the emission

reductions achievable from all sources

subject to BART located within the

region that contributes to visibility

impairment in the Class I area, based on

the analysis conducted under paragraph

(e)(1)(ii)(A) of this section.

(iii) If the State determines in

establishing BART that technological or

economic limitations on the

applicability of measurement

methodology to a particular source

would make the imposition of an

emission standard infeasible, it may

instead prescribe a design, equipment,

work practice, or other operational

standard, or combination thereof, to
35768 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

require the application of BART. Such

standard, to the degree possible, is to set

forth the emission reduction to be

achieved by implementation of such

design, equipment, work practice or

operation, and must provide for

compliance by means which achieve

equivalent results.

(iv) A requirement that each source

subject to BART be required to install

and operate BART as expeditiously as

practicable, but in no event later than 5

years after approval of the

implementation plan revision.

(v) A requirement that each source

subject to BART maintain the control

equipment required by this subpart and

establish procedures to ensure such

equipment is properly operated and

maintained.

(2) A State may opt to implement an

emissions trading program or other

alternative measure rather than to

require sources subject to BART to

install, operate, and maintain BART. To

do so, the State must demonstrate that

this emissions trading program or other

alternative measure will achieve greater

reasonable progress than would be

achieved through the installation and

operation of BART. To make this

demonstration, the State must submit an

implementation plan containing the

following plan elements and include

documentation for all required analyses:

(i) A demonstration that the emissions

trading program or other alternative

measure will achieve greater reasonable

progress than would have resulted from

the installation and operation of BART

at all sources subject to BART in the

State. This demonstration must be based

on the following:

(A) A list of all BART-eligible sources

within the State.

(B) An analysis of the best system of

continuous emission control technology

available and associated emission

reductions achievable for each source

within the State subject to BART. In this

analysis, the State must take into

consideration the technology available,

the costs of compliance, the energy and

nonair quality environmental impacts of

compliance, any pollution control

equipment in use at the source, and the

remaining useful life of the source. The

best system of continuous emission

control technology and the above factors

may be determined on a source category

basis. The State may elect to consider

both source-specific and category-wide

information, as appropriate, in

conducting its analysis.

(C) An analysis of the degree of

visibility improvement that would be

achieved in each mandatory Class I

Federal area as a result of the emission

reductions achievable from all such

sources subject to BART located within

the region that contributes to visibility

impairment in the Class I area, based on

the analysis conducted under paragraph

(e)(2)(i)(B) of this section.

(ii) A demonstration that the

emissions trading program or alternative

measure will apply, at a minimum, to

all BART-eligible sources in the State.

Those sources having a federally

enforceable emission limitation

determined by the State and approved

by EPA as meeting BART in accordance

with § 51.302(c) or paragraph (e)(1) of

this section do not need to meet the

requirements of the emissions trading

program or alternative measure, but may

choose to participate if they meet the

requirements of the emissions trading

program or alternative measure.

(iii) A requirement that all necessary

emission reductions take place during

the period of the first long-term strategy

for regional haze. To meet this

requirement, the State must provide a

detailed description of the emissions

trading program or other alternative

measure, including schedules for

implementation, the emission

reductions required by the program, all

necessary administrative and technical

procedures for implementing the

program, rules for accounting and

monitoring emissions, and procedures

for enforcement.

(iv) A demonstration that the

emission reductions resulting from the

emissions trading program or other

alternative measure will be surplus to

those reductions resulting from

measures adopted to meet requirements

of the CAA as of the baseline date of the

SIP.

(v) At the State’s option, a provision

that the emissions trading program or

other alternative measure may include a

geographic enhancement to the program

to address the requirement under

§ 51.302(c) related to BART for

reasonably attributable impairment from

the pollutants covered under the

emissions trading program or other

alternative measure.

(3) After a State has met the

requirements for BART or implemented

emissions trading program or other

alternative measure that achieve more

reasonable progress than the installation

and operation of BART, BART-eligible

sources will be subject to the

requirements of paragraph (d) of this

section in the same manner as other

sources.

(4) Any BART-eligible facility subject

to the requirement under paragraph (e)

of this section to install, operate, and

maintain BART may apply to the

Administrator for an exemption from

that requirement. An application for an

exemption will be subject to the

requirements of § 51.303 (a)(2) through

(h).

(f) Requirements for comprehensive

periodic revisions of implementation

plans for regional haze. Each State

identified in § 51.300(b)(3) must revise

and submit its regional haze

implementation plan revision to EPA by

July 31, 2018 and every ten years

thereafter. In each plan revision, the

State must evaluate and reassess all of

the elements required in paragraph (d)

of this section, taking into account

improvements in monitoring data

collection and analysis techniques,

control technologies, and other relevant

factors. In evaluating and reassessing

these elements, the State must address

the following:

(1) Current visibility conditions for

the most impaired and least impaired

days, and actual progress made towards

natural conditions during the previous

implementation period. The period for

calculating current visibility conditions

is the most recent five year period

preceding the required date of the

implementation plan submittal for

which data are available. Current

visibility conditions must be calculated

based on the annual average level of

visibility impairment for the most and

least impaired days for each of these

five years. Current visibility conditions

are the average of these annual values.

(2) The effectiveness of the long-term

strategy for achieving reasonable

progress goals over the prior

implementation period(s); and

(3) Affirmation of, or revision to, the

reasonable progress goal in accordance

with the procedures set forth in

paragraph (d)(1) of this section. If the

State established a reasonable progress

goal for the prior period which provided

a slower rate of progress than that

needed to attain natural conditions by

the year 2064, the State must evaluate

and determine the reasonableness,

based on the factors in paragraph

(d)(1)(i)(A) of this section, of additional

measures that could be adopted to

achieve the degree of visibility

improvement projected by the analysis

contained in the first implementation

plan described in paragraph (d)(1)(i)(B)

of this section.

(g) Requirements for periodic reports

describing progress towards the

reasonable progress goals. Each State

identified in § 51.300(b)(3) must submit

a report to the Administrator every 5

years evaluating progress towards the

reasonable progress goal for each

mandatory Class I Federal area located

within the State and in each mandatory

Class I Federal area located outside the

State which may be affected by
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35769

emissions from within the State. The

first progress report is due 5 years from

submittal of the initial implementation

plan addressing paragraphs (d) and (e)

of this section. The progress reports

must be in the form of implementation

plan revisions that comply with the

procedural requirements of § 51.102 and

§ 51.103. Periodic progress reports must

contain at a minimum the following

elements:

(1) A description of the status of

implementation of all measures

included in the implementation plan for

achieving reasonable progress goals for

mandatory Class I Federal areas both

within and outside the State.

(2) A summary of the emissions

reductions achieved throughout the

State through implementation of the

measures described in paragraph (g)(1)

of this section.

(3) For each mandatory Class I Federal

area within the State, the State must

assess the following visibility

conditions and changes, with values for

most impaired and least impaired days

expressed in terms of 5-year averages of

these annual values.

(i) The current visibility conditions

for the most impaired and least

impaired days;

(ii) The difference between current

visibility conditions for the most

impaired and least impaired days and

baseline visibility conditions;

(iii) The change in visibility

impairment for the most impaired and

least impaired days over the past 5

years;

(4) An analysis tracking the change

over the past 5 years in emissions of

pollutants contributing to visibility

impairment from all sources and

activities within the State. Emissions

changes should be identified by type of

source or activity. The analysis must be

based on the most recent updated

emissions inventory, with estimates

projected forward as necessary and

appropriate, to account for emissions

changes during the applicable 5-year

period.

(5) An assessment of any significant

changes in anthropogenic emissions

within or outside the State that have

occurred over the past 5 years that have

limited or impeded progress in reducing

pollutant emissions and improving

visibility.

(6) An assessment of whether the

current implementation plan elements

and strategies are sufficient to enable

the State, or other States with

mandatory Federal Class I areas affected

by emissions from the State, to meet all

established reasonable progress goals.

(7) A review of the State’s visibility

monitoring strategy and any

modifications to the strategy as

necessary.

(h) Determination of the adequacy of

existing implementation plan. At the

same time the State is required to

submit any 5-year progress report to

EPA in accordance with paragraph (g) of

this section, the State must also take one

of the following actions based upon the

information presented in the progress

report:

(1) If the State determines that the

existing implementation plan requires

no further substantive revision at this

time in order to achieve established

goals for visibility improvement and

emissions reductions, the State must

provide to the Administrator a negative

declaration that further revision of the

existing implementation plan is not

needed at this time.

(2) If the State determines that the

implementation plan is or may be

inadequate to ensure reasonable

progress due to emissions from sources

in another State(s) which participated in

a regional planning process, the State

must provide notification to the

Administrator and to the other State(s)

which participated in the regional

planning process with the States. The

State must also collaborate with the

other State(s) through the regional

planning process for the purpose of

developing additional strategies to

address the plan’s deficiencies.

(3) Where the State determines that

the implementation plan is or may be

inadequate to ensure reasonable

progress due to emissions from sources

in another country, the State shall

provide notification, along with

available information, to the

Administrator.

(4) Where the State determines that

the implementation plan is or may be

inadequate to ensure reasonable

progress due to emissions from sources

within the State, the State shall revise

its implementation plan to address the

plan’s deficiencies within one year.

(i) What are the requirements for State

and Federal Land Manager

coordination?

(1) By November 29, 1999, the State

must identify in writing to the Federal

Land Managers the title of the official to

which the Federal Land Manager of any

mandatory Class I Federal area can

submit any recommendations on the

implementation of this subpart

including, but not limited to:

(i) Identification of impairment of

visibility in any mandatory Class I

Federal area(s); and

(ii) Identification of elements for

inclusion in the visibility monitoring

strategy required by § 51.305 and this

section.

(2) The State must provide the Federal

Land Manager with an opportunity for

consultation, in person and at least 60

days prior to holding any public hearing

on an implementation plan (or plan

revision) for regional haze required by

this subpart. This consultation must

include the opportunity for the affected

Federal Land Managers to discuss their:

(i) Assessment of impairment of

visibility in any mandatory Class I

Federal area; and

(ii) Recommendations on the

development of the reasonable progress

goal and on the development and

implementation of strategies to address

visibility impairment.

(3) In developing any implementation

plan (or plan revision), the State must

include a description of how it

addressed any comments provided by

the Federal Land Managers.

(4) The plan (or plan revision) must

provide procedures for continuing

consultation between the State and

Federal Land Manager on the

implementation of the visibility

protection program required by this

subpart, including development and

review of implementation plan revisions

and 5-year progress reports, and on the

implementation of other programs

having the potential to contribute to

impairment of visibility in mandatory

Class I Federal areas.

9. A new § 51.309 is added to subpart

P to read as follows:

§ 51.309 Requirements related to the

Grand Canyon Visibility Transport

Commission.

(a) What is the purpose of this

section? This section establishes the

requirements for the first regional haze

implementation plan to address regional

haze visibility impairment in the 16

Class I areas covered by the Grand

Canyon Visibility Transport

Commission Report. For the years 2003

to 2018, certain States (defined in

paragraph (b) of this section as

Transport Region States) may choose to

implement the Commission’s

recommendations within the framework

of the national regional haze program

and applicable requirements of the Act

by complying with the provisions of this

section, as supplemented by an

approvable Annex to the Commission

Report as required by paragraph (f) of

this section. If a transport region State

submits an implementation plan which

is approved by EPA as meeting the

requirements of this section, it will be

deemed to comply with the

requirements for reasonable progress for

the period from approval of the plan to

2018.
35770 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

(b) Definitions. For the purposes of

this section:

(1) 16 Class I areas means the

following mandatory Class I Federal

areas on the Colorado Plateau: Grand

Canyon National Park, Sycamore

Canyon Wilderness, Petrified Forest

National Park, Mount Baldy Wilderness,

San Pedro Parks Wilderness, Mesa

Verde National Park, Weminuche

Wilderness, Black Canyon of the

Gunnison Wilderness, West Elk

Wilderness, Maroon Bells Wilderness,

Flat Tops Wilderness, Arches National

Park, Canyonlands National Park,

Capital Reef National Park, Bryce

Canyon National Park, and Zion

National Park.

(2) Transport Region State means one

of the States that is included within the

Transport Region addressed by the

Grand Canyon Visibility Transport

Commission (Arizona, California,

Colorado, Idaho, Nevada, New Mexico,

Oregon, Utah, and Wyoming).

(3) Commission Report means the

report of the Grand Canyon Visibility

Transport Commission entitled

‘‘Recommendations for Improving

Western Vistas,’’ dated June 10, 1996.

(4) Fire means wildfire, wildland fire

(including prescribed natural fire),

prescribed fire, and agricultural burning

conducted and occurring on Federal,

State, and private wildlands and

farmlands.

(5) Milestone means an average

percentage reduction in emissions,

expressed in tons per year, for a given

year or for a period of up to 5 years

ending in that year, compared to a 1990

actual emissions baseline.

(6) Mobile Source Emission Budget

means the lowest level of VOC, NOX,

SO2 elemental and organic carbon, and

fine particles which are projected to

occur in any area within the transport

region from which mobile source

emissions are determined to contribute

significantly to visibility impairment in

any of the 16 Class I areas.

(7) Geographic enhancement means a

method, procedure, or process to allow

a broad regional strategy, such as a

milestone or backstop market trading

program designed to achieve greater

reasonable progress than BART for

regional haze, to accommodate BART

for reasonably attributable impairment.

(c) Implementation Plan Schedule.

Each Transport Region State may meet

the requirements of § 51.308(b) through

(e) by electing to submit an

implementation plan that complies with

the requirements of this section. Each

Transport Region State must submit an

implementation plan addressing

regional haze visibility impairment in

the 16 Class I areas no later than

December 31, 2003. A Transport Region

State that elects not to submit an

implementation plan that complies with

the requirements of this section (or

whose plan does not comply with all of

the requirements of this section) is

subject to the requirements of § 51.308

in the same manner and to the same

extent as any State not included within

the Transport Region.

(d) Requirements of the first

implementation plan for States electing

to adopt all of the recommendations of

the Commission Report. Except as

provided for in paragraph (e) of this

section, each Transport Region State

must submit an implementation plan

that meets the following requirements:

(1) Time period covered. The

implementation plan must be effective

for the entire time period between

December 31, 2003 and December 31,

2018.

(2) Projection of visibility

improvement. For each of the 16

mandatory Class I areas located within

the Transport Region State, the plan

must include a projection of the

improvement in visibility conditions

(expressed in deciviews, and in any

additional ambient visibility metrics

deemed appropriate by the State)

expected through the year 2018 for the

most impaired and least impaired days,

based on the implementation of all

measures as required in the Commission

report and the provisions in this section.

The projection must be made in

consultation with other Transport

Region States with sources which may

be reasonably anticipated to contribute

to visibility impairment in the relevant

Class I area. The projection may be

based on a satisfactory regional analysis.

(3) Treatment of clean-air corridors.

The plan must describe and provide for

implementation of comprehensive

emission tracking strategies for clean-air

corridors to ensure that the visibility

does not degrade on the least-impaired

days at any of the 16 Class I areas. The

strategy must include:

(i) An identification of clean-air

corridors. The EPA will evaluate the

State’s identification of such corridors

based upon the reports of the

Commission’s Meteorology

Subcommittee and any future updates

by a successor organization;

(ii) Within areas that are clean-air

corridors, an identification of patterns of

growth or specific sites of growth that

could cause, or are causing, significant

emissions increases that could have, or

are having, visibility impairment at one

or more of the 16 Class I areas.

(iii) In areas outside of clean-air

corridors, an identification of significant

emissions growth that could begin, or is

beginning, to impair the quality of air in

the corridor and thereby lead to

visibility degradation for the leastimpaired days in one or more of the 16

Class I areas.

(iv) If impairment of air quality in

clean air corridors is identified pursuant

to paragraphs (d)(3)(ii) and (iii) of this

section, an analysis of the effects of

increased emissions, including

provisions for the identification of the

need for additional emission reductions

measures, and implementation of the

additional measures where necessary.

(v) A determination of whether other

clean air corridors exist for any of the

16 Class I areas. For any such clean air

corridors, an identification of the

necessary measures to protect against

future degradation of air quality in any

of the 16 Class I areas.

(4) Implementation of stationary

source reductions. The first

implementation plan submission must

include:

(i) Monitoring and reporting of sulfur

dioxide emissions. The plan submission

must include provisions requiring the

monitoring and reporting of actual

stationary source sulfur dioxide

emissions within the State. The

monitoring and reporting data must be

sufficient to determine whether a 13

percent reduction in actual stationary

source sulfur dioxide emissions has

occurred between the years 1990 and

2000, and whether milestones required

by paragraph (f)(1)(i) of this section have

been achieved for the transport region.

The plan submission must provide for

reporting of these data by the State to

the Administrator. Where procedures

developed under paragraph (f)(1)(ii) of

this section and agreed upon by the

State include reporting to a regional

planning organization, the plan

submission must provide for reporting

to the regional planning body in

addition to the Administrator.

(ii) Criteria and procedures for a

market trading program. The plan must

include the criteria and procedures for

activating a market trading program or

other program consistent with

paragraph (f)(1)(i) of this section if an

applicable regional milestone is

exceeded, procedures for operation of

the program, and implementation plan

assessments and provisions for

implementation plan assessments of the

program in the years 2008, 2013, and

2018.

(iii) Provisions for activating a market

trading program. Provisions to activate

the market trading program or other

program within 12 months after the

emissions for the region are determined

to exceed the applicable emission

reduction milestone, and to assure that
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35771

all affected sources are in compliance

with allocation and other requirements

within 5 years after the emissions for

the region are determined to exceed the

applicable emission reduction

milestone.

(iv) Provisions for market trading

program compliance reporting. If the

market trading program has been

activated, the plan submission must

include provisions requiring the State to

provide annual reports assuring that all

sources are in compliance with

applicable requirements of the market

trading program.

(v) Provisions for stationary source

NOX and PM. The plan submission must

include a report which assesses

emissions control strategies for

stationary source NOX and PM, and the

degree of visibility improvement that

would result from such strategies. In the

report, the State must evaluate and

discuss the need to establish emission

milestones for NOX and PM to avoid any

net increase in these pollutants from

stationary sources within the transport

region, and to support potential future

development and implementation of a

multipollutant and possibly multisource

market-based program. The plan

submission must provide for an

implementation plan revision,

containing any necessary long-term

strategies and BART requirements for

stationary source PM and NOX

(including enforceable limitations,

compliance schedules, and other

measures) by no later than December 31,

2008.

(5) Mobile sources. The plan

submission must provide for:

(i) Statewide inventories of current

annual emissions and projected future

annual emissions of VOc, NOX, SO2,

elemental carbon, organic carbon, and

fine particles from mobile sources for

the years 2003 to 2018. The future year

inventories must include projections for

the year 2005, or an alternative year that

is determined by the State to represent

the year during which mobile source

emissions will be at their lowest levels

within the State.

(ii) A determination whether mobile

source emissions in any areas of the

State contribute significantly to

visibility impairment in any of the 16

Class I Areas, based on the statewide

inventory of current and projected

mobile source emissions.

(iii) For States with areas in which

mobile source emissions are found to

contribute significantly to visibility

impairment in any of the 16 Class I

areas:

(A) The establishment and

documentation of a mobile source

emissions budget for any such area,

including provisions requiring the State

to restrict the annual VOC, NOX, SO2,

elemental and organic carbon, and/or

fine particle mobile source emissions to

their projected lowest levels, to

implement measures to achieve the

budget or cap, and to demonstrate

compliance with the budget.

(B) An emission tracking system

providing for reporting of annual mobile

source emissions from the State in the

periodic implementation plan revisions

required by paragraph (d)(10) of this

section. The emission tracking system

must be sufficient to determine the

States’ contribution toward the

Commission’s objective of reducing

emissions from mobile sources by 2005

or an alternate year that is determined

by the State to represent the year during

which mobile source emissions will be

at their lowest levels within the State,

and to ensure that mobile source

emissions do not increase thereafter.

(iv) Interim reports to EPA and the

public in years 2003, 2008, 2013, and

2018 on the implementation status of

the regional and local strategies

recommended by the Commission

Report to address mobile source

emissions.

(6) Programs related to fire. The plan

must provide for:

(i) Documentation that all Federal,

State, and private prescribed fire

programs within the State evaluate and

address the degree visibility impairment

from smoke in their planning and

application. In addition the plan must

include smoke management programs

that include all necessary components

including, but not limited to, actions to

minimize emissions, evaluation of

smoke dispersion, alternatives to fire,

public notification, air quality

monitoring, surveillance and

enforcement, and program evaluation.

(ii) A statewide inventory and

emissions tracking system (spatial and

temporal) of VOC, NOX, elemental and

organic carbon, and fine particle

emissions from fire. In reporting and

tracking emissions from fire from within

the State, States may use information

from regional data-gathering and

tracking initiatives.

(iii) Identification and removal

wherever feasible of any administrative

barriers to the use of alternatives to

burning in Federal, State, and private

prescribed fire programs within the

State.

(iv) Enhanced smoke management

programs for fire that consider visibility

effects, not only health and nuisance

objectives, and that are based on the

criteria of efficiency, economics, law,

emission reduction opportunities, land

management objectives, and reduction

of visibility impact.

(v) Establishment of annual emission

goals for fire, excluding wildfire, that

will minimize emission increases from

fire to the maximum extent feasible and

that are established in cooperation with

States, tribes, Federal land management

agencies, and private entities.

(7) Area sources of dust emissions

from paved and unpaved roads. The

plan must include an assessment of the

impact of dust emissions from paved

and unpaved roads on visibility

conditions in the 16 Class I Areas. If

such dust emissions are determined to

be a significant contributor to visibility

impairment in the 16 Class I areas, the

State must implement emissions

management strategies to address the

impact as necessary and appropriate.

(8) Pollution prevention. The plan

must provide for:

(i) An initial summary of all pollution

prevention programs currently in place,

an inventory of all renewable energy

generation capacity and production in

use, or planned as of the year 2002

(expressed in megawatts and megawatthours), the total energy generation

capacity and production for the State,

the percent of the total that is renewable

energy, and the State’s anticipated

contribution toward the renewable

energy goals for 2005 and 2015, as

provided in paragraph (d)(8)(vi) of this

section.

(ii) Programs to provide incentives

that reward efforts that go beyond

compliance and/or achieve early

compliance with air-pollution related

requirements.

(iii) Programs to preserve and expand

energy conservation efforts.

(iv) The identification of specific

areas where renewable energy has the

potential to supply power where it is

now lacking and where renewable

energy is most cost-effective.

(v) Projections of the short- and longterm emissions reductions, visibility

improvements, cost savings, and

secondary benefits associated with the

renewable energy goals, energy

efficiency and pollution prevention

activities.

(vi) A description of the programs

relied on to achieve the State’s

contribution toward the Commission’s

goal that renewable energy will

comprise 10 percent of the regional

power needs by 2005 and 20 percent by

2015, and a demonstration of the

progress toward achievement of the

renewable energy goals in the years

2003, 2008, 2013, and 2018. This

description must include

documentation of the potential for

renewable energy resources, the
35772 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

percentage of renewable energy

associated with new power generation

projects implemented or planned, and

the renewable energy generation

capacity and production in use and

planned in the State. To the extent that

it is not feasible for a State to meet its

contribution to the regional renewable

energy goals, the State must identify in

the progress reports the measures

implemented to achieve its contribution

and explain why meeting the State’s

contribution was not feasible.

(9) Implementation of additional

recommendations. The plan must

provide for implementation of all other

recommendations in the Commission

report that can be practicably included

as enforceable emission limits,

schedules of compliance, or other

enforceable measures (including

economic incentives) to make

reasonable progress toward remedying

existing and preventing future regional

haze in the 16 Class I areas. The State

must provide a report to EPA and the

public in 2003, 2008, 2013, and 2018 on

the progress toward developing and

implementing policy or strategy options

recommended in the Commission

Report.

(10) Periodic implementation plan

revisions. Each Transport Region State

must submit to the Administrator

periodic reports in the years 2008, 2013,

and 2018. The progress reports must be

in the form of implementation plan

revisions that comply with the

procedural requirements of § 51.102 and

§ 51.103.

(i) The report will assess the area for

reasonable progress as provided in this

section for mandatory Class I Federal

area(s) located within the State and for

mandatory Class I Federal area(s)

located outside the State which may be

affected by emissions from within the

State. This demonstration may be based

on assessments conducted by the States

and/or a regional planning body. The

progress reports must contain at a

minimum the following elements:

(A) A description of the status of

implementation of all measures

included in the implementation plan for

achieving reasonable progress goals for

mandatory Class I Federal areas both

within and outside the State.

(B) A summary of the emissions

reductions achieved throughout the

State through implementation of the

measures described in paragraph

(d)(10)(i)(A) of this section.

(C) For each mandatory Class I

Federal area within the State, an

assessment of the following: the current

visibility conditions for the most

impaired and least impaired days; the

difference between current visibility

conditions for the most impaired and

least impaired days and baseline

visibility conditions; the change in

visibility impairment for the most

impaired and least impaired days over

the past 5 years.

(D) An analysis tracking the change

over the past 5 years in emissions of

pollutants contributing to visibility

impairment from all sources and

activities within the State. Emissions

changes should be identified by type of

source or activity. The analysis must be

based on the most recent updated

emissions inventory, with estimates

projected forward as necessary and

appropriate, to account for emissions

changes during the applicable 5-year

period.

(E) An assessment of any significant

changes in anthropogenic emissions

within or outside the State that have

occurred over the past 5 years that have

limited or impeded progress in reducing

pollutant emissions and improving

visibility.

(F) An assessment of whether the

current implementation plan elements

and strategies are sufficient to enable

the State, or other States with

mandatory Federal Class I areas affected

by emissions from the State, to meet all

established reasonable progress goals.

(G) A review of the State’s visibility

monitoring strategy and any

modifications to the strategy as

necessary.

(ii) At the same time the State is

required to submit any 5-year progress

report to EPA in accordance with

paragaph (d)(10)(i) of this section, the

State must also take one of the following

actions based upon the information

presented in the progress report:

(A) If the State determines that the

existing implementation plan requires

no further substantive revision at this

time in order to achieve established

goals for visibility improvement and

emissions reductions, the State must

provide to the Administrator a negative

declaration that further revision of the

existing implementation plan is not

needed at this time.

(B) If the State determines that the

implementation plan is or may be

inadequate to ensure reasonable

progress due to emissions from sources

in another State(s) which participated in

a regional planning process, the State

must provide notification to the

Administrator and to the other State(s)

which participated in the regional

planning process with the States. The

State must also collaborate with the

other State(s) through the regional

planning process for the purpose of

developing additional strategies to

address the plan’s deficiencies.

(C) Where the State determines that

the implementation plan is or may be

inadequate to ensure reasonable

progress due to emissions from sources

in another country, the State shall

provide notification, along with

available information, to the

Administrator.

(D) Where the State determines that

the implementation plan is or may be

inadequate to ensure reasonable

progress due to emissions from within

the State, the State shall develop

additional strategies to address the plan

deficiencies and revise the

implementation plan no later than one

year from the date that the progress

report was due.

(11) State planning and interstate

coordination. In complying with the

requirements of this section, States may

include emission reductions strategies

that are based on coordinated

implementation with other States.

Examples of these strategies include

economic incentive programs and

transboundary emissions trading

programs. The implementation plan

must include documentation of the

technical and policy basis for the

individual State apportionment (or the

procedures for apportionment

throughout the trans-boundary region),

the contribution addressed by the

State’s plan, how it coordinates with

other State plans, and compliance with

any other appropriate implementation

plan approvability criteria. States may

rely on the relevant technical, policy

and other analyses developed by a

regional entity (such as the Western

Regional Air Partnership) in providing

such documentation. Conversely, States

may elect to develop their own

programs without relying on work

products from a regional entity.

(12) Tribal implementation.

Consistent with 40 CFR Part 49, tribes

within the Transport Region may

implement the required visibility

programs for the 16 Class I areas, in the

same manner as States, regardless of

whether such tribes have participated as

members of a visibility transport

commission.

(e) States electing not to implement

the commission recommendations. Any

Transport Region State may elect not to

implement the Commission

recommendations set forth in paragraph

(d) of this section. Such States are

required to comply with the timelines

and requirements of § 51.308. Any

Transport Region State electing not to

implement the Commission

recommendations must advise the other

States in the Transport Region of the

nature of the program and the effect of

the program on visibility-impairing
Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations 35773

emissions, so that other States can take

this information into account in

developing programs under this section.

(f) Annex to the Commission Report.

(1) A Transport Region State may

choose to comply with the provisions of

this section and by doing so shall satisfy

the requirements of § 51.308(b) through

(e) only if the Grand Canyon Visibility

Transport Commission (or a regional

planning body formed to implement the

Commission recommendations) submits

a satisfactory annex to the Commission

Report no later than October 1, 2000. To

be satisfactory, the Annex must contain

the following elements:

(i) The annex must contain

quantitative emission reduction

milestones for stationary source sulfur

dioxide emissions for the reporting

years 2003, 2008, 2013 and 2018. The

milestones must provide for steady and

continuing emission reductions for the

2003–2018 time period consistent with

the Commission’s definition of

reasonable progress, its goal of 50 to 70

percent reduction in sulfur dioxide

emissions from 1990 actual emission

levels by 2040, applicable requirements

under the CAA, and the timing of

implementation plan assessments of

progress and identification of

deficiencies which will be due in the

years 2008, 2013, and 2018. The

emission reduction milestones must be

shown to provide for greater reasonable

progress than would be achieved by

application of best available retrofit

technology (BART) pursuant to

§ 51.308(e)(2) and would be approvable

in lieu of BART.

(ii) The annex must contain

documentation of the market trading

program or other programs to be

implemented pursuant to paragraph

(d)(4) of this section if current programs

and voluntary measures are not

sufficient to meet the required emission

reduction milestones. This

documentation must include model

rules, memoranda of understanding, and

other documentation describing in

detail how emission reduction progress

will be monitored, what conditions will

require the market trading program to be

activated, how allocations will be

performed, and how the program will

operate.

(2) The Commission may elect, at the

same time it submits the annex, to make

recommendations intended to

demonstrate reasonable progress for

other mandatory Class I areas (beyond

the original 16) within the Transport

Region States, including the technical

and policy justification for these

additional mandatory Class I Federal

areas in accordance with the provisions

of paragraph (g) of this section.

(3) The EPA will publish the annex

upon receipt. If EPA finds that the

annex meets the requirements of

paragraph (f)(1) of this section and

assures reasonable progress, then, after

public notice and comment, will amend

the requirements of paragraph (d)(4) of

this section to incorporate the

provisions of the annex within 1 year

after EPA receives the annex. If EPA

finds that the annex does not meet the

requirements of paragraph (f)(1) of this

section, or does not assure reasonable

progress, or if EPA finds that the annex

is not received, then each Transport

Region State must submit an

implementation plan for regional haze

meeting all of the requirements of

§ 51.308.

(4) In accordance with the provisions

under paragraph (f)(1) of this section,

the annex may include a geographic

enhancement to the program provided

for in paragraph (d)(4) of this section to

address the requirement under

§ 51.302(c) related to Best Available

Retrofit Technology for reasonably

attributable impairment from the

pollutants covered by the milestones or

the backstop market trading program.

The geographic enhancement program

may include an appropriate level of

reasonably attributable impairment

which may require additional emission

reductions over and above those

achieved under the milestones defines

in paragraph (f)(1)(i) of this section.

(g) Additional Class I areas. The

following submittals must be made by

Transport Region States implementing

the provisions of this section as the

basis for demonstrating reasonable

progress for additional Class I areas in

the Transport Region States. If a

Transport Region State submits an

implementation plan which is approved

by EPA as meeting the requirements of

this section, it will be deemed to

comply with the requirements for

reasonable progress for the period from

approval of the plan to 2018.

(1) In the plan submitted for the 16

Class I areas no later than December 31,

2003, a declaration indicating whether

other Class I areas will be addressed

under § 51.308 or paragraphs (g)(2) and

(3) of this section.

(2) In a plan submitted no later than

December 31, 2008, provide a

demonstration of expected visibility

conditions for the most impaired and

least impaired days at the additional

mandatory Class I Federal area(s) based

on emissions projections from the longterm strategies in the implementation

plan. This demonstration may be based

on assessments conducted by the States

and/or a regional planning body.

(3) In a plan submitted no later than

December 31, 2008, provide revisions to

the plan submitted under paragraph (c)

of this section, including provisions to

establish reasonable progress goals and

implement any additional measures

necessary to demonstrate reasonable

progress for the additional mandatory

Federal Class I areas. These revisions

must comply with the provisions of

§ 51.308(d)(1) through (4).

(4) The following provisions apply for

Transport Region States establishing

reasonable progress goals and adopting

any additional measures for Class I areas

other than the 16 Class I areas under

paragraphs (g)(2) and (3) of this section.

(i) In developing long-term strategies

pursuant to § 51.308(d)(3), the State may

build upon the strategies implemented

under paragraph (d) of this section, and

take full credit for the visibility

improvement achieved through these

strategies.

(ii) The requirement under § 51.308(e)

related to Best Available Retrofit

Technology for regional haze is deemed

to be satisfied for pollutants addressed

by the milestones and backstop trading

program if, in establishing the emission

reductions milestones under paragraph

(f) of this section, it is shown that

greater reasonable progress will be

achieved for these Class I areas than

would be achieved through the

application of source-specific BART

emission limitations under

§ 51.308(e)(1).

(iii) The Transport Region State may

consider whether any strategies

necessary to achieve the reasonable

progress goals required by paragraph

(g)(3) of this section are incompatible

with the strategies implemented under

paragraph (d) of this section to the

extent the State adequately

demonstrates that the incompatibility is

related to the costs of the compliance,

the time necessary for compliance, the

energy and no air quality environmental

impacts of compliance, or the remaining

useful life of any existing source subject

to such requirements.

10. In the sections listed in the first

column remove the reference listed in

the middle column and add the

reference listed in the third column in

its place:
35774 Federal Register / Vol. 64, No. 126 / Thursday, July 1, 1999 / Rules and Regulations

Section Remove Add

51.301(v) ...................................................................................... Section 303 ................................................................................ § 51.303

51.302(c)(2)(i) .............................................................................. Section 305 ................................................................................ § 51.305

51.302(c)(2)(i) .............................................................................. Section 306 ................................................................................ § 51.306

51.302(c)(2)(i) .............................................................................. Section 300(a) ............................................................................ § 51.300(a)

51.302(c)(4)(i) .............................................................................. Section 304(b) ............................................................................ § 51.304(b)

51.303(a)(1) ................................................................................. Section 302 ................................................................................ § 51.302

51.303(c) ...................................................................................... Section 303 ................................................................................ § 51.303

51.303(d) ..................................................................................... Section 303 ................................................................................ § 51.303

51.303(g) ..................................................................................... Section 303 ................................................................................ § 51.303

51.303(h) ..................................................................................... Section 303 ................................................................................ § 51.303

51.304(c) ...................................................................................... Section 306(c) ............................................................................ § 51.306(c)

51.306(a)(1) ................................................................................. Section 300(a) ............................................................................ § 51.300(a)

51.306(c)(6) ................................................................................. Section 303 ................................................................................ § 51.303

51.307(b)(1) ................................................................................. Section 304 ................................................................................ § 51.304

51.307(b)(1) ................................................................................. Section 304(d) ............................................................................ § 51.304(d)

51.307(c) ...................................................................................... Section 300(a) ............................................................................ § 51.300(a)

[FR Doc. 99–13941 Filed 6–30–99; 8:45 am]

BILLING CODE 6560–50–U
ATTACHMENT E 

Summary of 40 CFR Sections 51.302 through 51.307
P:\23\62\833 - MPCA Tac BART\Task 2\Task 2B\51.302-51.307.doc 1 of 3 4/16/2003 

40 CFR Part 51 Subpart P – Protection of Visibility, Sections 

51.302 through 51.307 

The requirements in 40 CFR sections 51.302-51.307 relate primarily to the reasonably attributable 

visibility impairment rules originally promulgated in 1980. Therefore, they are included as an 

attachment to the section in the report discussing the regional haze rule. 

1 40 CFR 51.302 Implementation control strategies for reasonably attributable 

visibility impairment. 

This section establishes SIP revision procedures, state and FLM coordination, and general plan 

requirements for reasonably attributable visibility impairment. 

The SIP revision procedures require each state to have submitted a SIP by September 2, 1981 to address 

the reasonably attributable visibility impairment requirements. The section also requires states to 

coordinate with FLMs for recommendations and consultations on the proposed SIP and implementation 

of the visibility protection program. 

General plan requirements include: a long-term strategy to make reasonable progress toward the 

national goal; an assessment of visibility impairment and a discussion of how each element of the plan 

relates to the preventing of future or remedying of existing impairment of visibility in Class I areas 

within the state; and emission limitations representing BART and schedules for compliance with BART 

for each existing stationary facility subject to the rule. 

How does this provision relate to BART at taconite facilities? 

This provision also requires the MPCA to identify and analyze for BART each existing stationary 

facility which may reasonably be anticipated to cause or contribute to impairment of visibility in a Class 

I area. If a FLM certifies that there exists reasonably attributable impairment of visibility in a Class I 

area, then the state sets limits or other requirements as described below: 

(1) The state must identify and analyze for BART each existing stationary facility which may 

reasonably be anticipated to cause or contribute to impairment of visibility in any Class I area where 

the impairment is reasonably attributable to that existing stationary facility. 

(2) If the state determines that technological or economic limitations on the applicability of 

measurement methodology to a particular existing stationary facility would make the imposition of 

an emission standard infeasible it may instead prescribe a design, equipment, work practice, or other 

operational standard, or combination thereof, to require the application of BART. Such standard 

will set forth the emission reduction to be achieved by implementation of such design, equipment, 

work practice or operation, and must provide for compliance by means which achieve equivalent 

results. 

This provision requires taconite facilities to apply BART as expeditiously as practicable, but not later 

than five years after plan approval. In addition, taconite facilities are required to analyze BART when 

new technology for control of the pollutant becomes available if: 

 The pollutant is emitted by that existing stationary facility, 

 Controls representing BART for the pollutant have not previously been required under this subpart, 

and 
P:\23\62\833 - MPCA Tac BART\Task 2\Task 2B\51.302-51.307.doc 2 of 3 4/16/2003 

 The impairment of visibility in any Class I area is reasonably attributable to the emissions of that 

pollutant. 

2 40 CFR 51.303 Exemptions from control. 

Under this section, any existing stationary facility required to install, operate, and maintain BART may 

apply for an exemption from that requirement. The application must document the impact of the 

source's emissions on visibility in any Class I area and demonstrate that the source does not or will not, 

by itself or in combination with other sources, emit any air pollutants which may be reasonably 

anticipated to cause or contribute to significant visibility impairment in any Class I area. 

The exemption application requirements and approval procedure is outlined below: 

(1) The exemption application must include MPCA concurrence and it may include an initial 

recommendation or other comments from the FLMs, 

(2) Notice and opportunity for a public hearing, 

(3) EPA may then grant or deny the application, 

(4) FLMs must concur with the EPA determination before the exemption is finally granted. 

How does this provision relate to BART at taconite facilities? 

This provision allows taconite facilities to apply for an exemption from BART if it can demonstrate that 

it does not emit any air pollutants that may be reasonably anticipated to cause or contribute to significant 

visibility impairment in any Class I area. 

3 40 CFR 51.304 Identification of integral vistas. 

This section allows FLMs to identify any integral vista by December 31, 1985. An integral vista is a 

view perceived from within the Class I area of a specific landmark or panorama located outside the 

boundary of the Class I area. 

How does this provision relate to BART at taconite facilities? 

Since FLMs may no longer identify an integral vista and since there are none in Minnesota, this 

provision has no impact on taconite facilities. 

4 40 CFR 51.305 Monitoring for reasonably attributable visibility impairment. 

This section requires each state to include in the plan a strategy for evaluating reasonably attributable 

visibility impairment in any Class I area by visual observation or other appropriate monitoring 

techniques. States should follow EPA’s June 1999 Visibility Guidance document in developing this 

strategy. 

How does this provision relate to BART at taconite facilities? 

This provision requires the MPCA to include in the SIP a strategy for evaluating reasonably attributable 

visibility impairment in Class I areas by visual observation or other appropriate monitoring techniques. 

To date, the Minnesota SIP does not address a visibility monitoring strategy. 
P:\23\62\833 - MPCA Tac BART\Task 2\Task 2B\51.302-51.307.doc 3 of 3 4/16/2003 

5 40 CFR 51.306 Long-term strategy requirements for reasonably attributable 

visibility impairment. 

This section requires each plan to include a long-term (10-15 years) strategy for making reasonable 

progress toward the national goal and discusses factors the state must consider in the development of the 

strategy. This section also describes the required elements of and schedule for review as well as report 

requirements. 

How does this provision relate to BART at taconite facilities? 

This provision requires the MPCA to include in the SIP a long-term (10-15 years) strategy for each 

Class I area in Minnesota and each Class I area located outside the state which may be affected by 

sources within the state for making reasonable progress toward the national goal. It also establishes the 

criteria of and timeline for periodic review and revision of the strategy. Note that the long-term strategy 

is separate from the regional haze plan required by 40 CFR 51.308(b) and (c). 

6 40 CFR 51.307 New source review. 

This section discusses the requirements that a plan must provide for in the event of any new major 

stationary source or major modification that would be constructed in an area that is designated 

attainment or unclassified. Requirements include: 

 Notification to affected FLMs of a proposed new major stationary source or major modification that 

may affect visibility in any Class I area 

 Advanced notification of a permit application of a source that may affect visibility in the state 

 Consideration of any analysis performed by the FLM that a proposed new major stationary source or 

major modification may have an adverse impact on visibility in any Class I area. 

This section also requires that the plan provide for the review of any new major stationary source or 

major modification that may have an impact on any integral vista of a Class I area or that proposes to 

locate in an area classified as nonattainment that may have an impact on visibility in any Class I area. 

How does this provision relate to BART at taconite facilities? 

Because no integral vistas have been established in the United States and no nonattainment areas are 

present in northern Minnesota where a new or modified taconite plant would be located, this provision 

has little impact on the taconite industry. 
ATTACHMENT F 

July 20, 2001, Federal Register Notice – Proposed Guidelines for Best 

Available Retrofit Technology (BART) Determinations Under the 

Regional Haze Regulations; Proposed Rule 
Friday,

July 20, 2001

Part III

Environmental

Protection Agency

40 CFR Part 51

Proposed Guidelines for Best Available

Retrofit Technology (BART)

Determinations Under the Regional Haze

Regulations; Proposed Rule

38108 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Part 51

[FRL–6934–4]

Proposed Guidelines for Best

Available Retrofit Technology (BART)

Determinations Under the Regional

Haze Regulations

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Proposed rule.

SUMMARY: The purpose of this proposal

is to request comment on EPA’s

proposed guidelines for implementation

of the best available retrofit technology

(BART) requirements under the regional

haze rule which was published on July

1, 1999 (64 FR 35714). We propose to

add the guidelines as appendix Y to 40

CFR part 51. We propose to add

regulatory text requiring that these

guidelines be used for addressing BART

determinations under the regional haze

rule. In addition, we are proposing one

revision to guidelines issued in 1980 for

facilities contributing to ‘‘reasonably

attributable’’ visibility impairment.

DATES: We are requesting written

comments by September 18, 2001. The

EPA has scheduled two public hearings

on this proposed rule. The first public

hearing will be held on August 21 in

Arlington, Virginia. The second public

hearing will be held on August 27 in

Chicago, Illinois. (See following section

for times and addresses.)

ADDRESSES: Docket. Information related

to the BART guidelines is available for

inspection at the Air and Radiation

Docket and Information Center, docket

number A–2000–28. The docket is

located at the U.S. Environmental

Protection Agency, 401 M Street, SW,

Room M–1500, Washington, DC 20460,

telephone (202) 260–7548. The docket is

available for public inspection and

copying between 8:00 a.m. and 5:30

p.m., Monday through Friday, excluding

legal holidays. A reasonable fee may be

charged for copying.

You should submit comments on

today’s proposal and the materials

referenced herein (in duplicate if

possible) to the Air and Radiation

Docket and Information Center (6102),

Attention: Docket No. A–2000–28, U.S.

Environmental Protection Agency, 1200

Pennsylvania Avenue, NW, Washington,

DC 20460. You may also submit

comments to EPA by electronic mail at

the following address: A-and-RDocket@epamail.epa.gov. Electronic

comments must be submitted as an

ASCII file avoiding the use of special

characters and any form of encryption.

All comments and data in electronic

form must be identified by the docket

number [A–2000–28]. Electronic

comments on this proposed rule also

may be filed online at many Federal

Depository Libraries.

Public Hearings. The first public

hearing on this proposed rule will be

held on August 21 at 10:00 am at the

Crowne Plaza Hotel, 1489 Jefferson

Davis Highway, Arlington, VA 22202.

The hotel is located near the Crystal

City metro stop. The second public

hearing will be held on August 27 at

10:00 am at the Metcalfe Federal

Building, Room 331, 77 West Jackson

Boulevard, Chicago, IL 60604.

If you wish to attend either public

hearing or wish to present oral

testimony, please send notification no

later than one week prior to the date of

the public hearing to Ms. Nancy Perry,

Office of Air Quality Planning and

Standards, Air Quality Strategies and

Standards Division, MD–15, Research

Triangle Park, NC 27711, telephone

(919) 541–5628, e-mail

perry.nancy@epa.gov.

Oral testimony will be limited to 5

minutes each. The hearing will be

strictly limited to the subject matter of

the proposal, the scope of which is

discussed below. Any member of the

public may file a written statement by

the close of the comment period.

Written statements (duplicate copies

preferred) should be submitted to

Docket No. A–2000–28 at the address

listed above for submitting comments.

The hearing schedule, including lists of

speakers, will be posted on EPA’s

webpage at http://www.epa.gov/air/

visibility/whatsnew.html. A verbatim

transcript of the hearings and written

statements will be made available for

copying during normal working hours at

the Air and Radiation Docket and

Information Center at the address listed

above.

FOR FURTHER INFORMATION CONTACT: Tim

Smith (telephone 919–541–4718), Mail

Drop 15, EPA, Air Quality Strategies

and Standards Division, Research

Triangle Park, North Carolina, 27711.

Internet address: smith.tim@epa.gov.

SUPPLEMENTARY INFORMATION: We are

providing the public with the

opportunity to comment on EPA’s

Proposed BART Guidelines and the

accompanying regulatory text.

Table of Contents

I. Background on BART Guidelines

A. Commitment in the Preamble to the

Regional Haze Rule

B. Statutory Requirement for BART

Guidelines

II. Proposed Amendments to Part 51

III. Revision to 1980 BART Guidelines for

‘‘Reasonably Attributable’’ Visibility

Impairment

IV. Administrative Requirements

A. Regulatory Planning and Review by the

Office of Management and Budget (OMB)

(Executive Order 12866)

B. Regulatory Flexibility Act

C. Paperwork Reduction Act—Impact on

Reporting Requirements

D. Unfunded Mandates Reform Act

E. Environmental Justice—Executive Order

12898

F. Protection of Children from

Environmental Health Risks and Safety

Risks—Executive Order 13045

G. Executive Order 13132: Federalism

H. Executive Order 13084: Consultation

and Coordination with Indian Tribal

Governments

I. National Technology Transfer and

Advancement Act

J. Executive Order 13211. Actions

Concerning Regulations That

Significantly Affect Energy Supply,

Distribution, or Use.

K. Guidelines for BART Determinations

Under the Regional Haze Rule

I. Background on BART Guidelines

A. Commitment in the Preamble to the

Regional Haze Rule

The EPA included in the final

regional haze rule a requirement for

BART for certain large stationary

sources put in place between 1962 and

1977. We discuss these requirements in

detail in the preamble to the final rule

(see 64 FR 35737–35743). The

regulatory requirements for BART are

codified in 40 CFR 51.308(e). In the

preamble, we committed to issuing

further guidelines to clarify the

requirements of the BART provision.

The purpose of this notice is to provide

the public with an opportunity to

comment on the draft guidelines and the

accompanying regulatory text.

B. Statutory Requirement for BART

Guidelines

Section 169A(b)(1) of the Clean Air

Act (CAA) requires EPA to provide

guidelines to States on the

implementation of the visibility

program. Moreover, the last sentence of

section 169A(b) states:

In the case of a fossil-fuel fired generating

powerplant having a capacity in excess of

750 megawatts, the emission limitations

required under this paragraph shall be

determined pursuant to guidelines,

promulgated by the Administrator under

paragraph (1)

We interpret this statutory requirement

as clearly requiring EPA to publish

BART guidelines and to require that

States follow the guidelines in

establishing BART emission limitations

for power plants with a total capacity

exceeding the 750 megawatt cutoff. The

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38109

1U.S. Environmental Protection Agency,

Guidelines for Determining Best Available Retrofit

Technology for Coal-fired Power Plants and Other

Existing Stationary Facilities, EPA–450/3–80–009b,

Office of Air Quality Planning and Standards,

Research Triangle Park, N.C., November 1980 (1980

BART Guidelines).

statute is less clear regarding whether

the guidelines must be used for sources

other than 750 megawatt power plants;

however, today’s proposed rule would

require States to use the guidelines for

all of the 26 categories. We believe it is

reasonable that consistent, rigorous

approaches be used for all BART source

categories. In addition, we believe it is

important to provide for consistent

approaches to identifying the sources in

the remaining categories which are

BART-eligible. We request comment on

whether the regional haze rule should:

(1) Require use of the guidelines only

for 750 megawatt utilities, with the

guidelines applying as guidance for the

remaining categories, or (2)require use

of the guidelines for all of the affected

source categories.

II. Proposed Amendments to Part 51

We propose:

(1) BART guidelines, to be added as

appendix Y to 40 CFR part 51,

(2) regulatory text, to be added as subparagraph 51.308(e)(1)(C), requiring the

use of the guidelines.

Overview of Proposed Appendix Y

We discuss the following general

topics in appendix Y, which are

organized into the following sections:

—Introduction. Section I provides an

overview of the BART requirement in

the regional haze rule and in the CAA,

and an overview of the guidelines.

—Identification of BART-eligible

sources. Section II is a step-by-step

process for identifying BART-eligible

sources.

—Identification of sources subject to

BART. Sources ‘‘subject to BART’’ are

those BART-eligible sources which

‘‘emit a pollutant which may

reasonably be anticipated to cause or

contribute to any impairment of

visibility in any Class I area.’’ We

discuss considerations for identifying

sources subject to BART in section III

of the proposed appendix Y.

—Engineering analysis. For each source

subject to BART, the next step is to

conduct an engineering analysis of

emissions control alternatives. This

step requires the identification of

available, technically feasible, retrofit

technologies, and for each technology

identified, analysis of the cost of

compliance, and the energy and nonair quality environmental impacts,

taking into account the remaining

useful life and existing control

technology present at the source. For

each source, a ‘‘best system of

continuous emission reduction’’ is

selected based upon this engineering

analysis. Guidelines for the

engineering analysis are described in

section IV of the proposed appendix

Y.

—Cumulative air quality analysis. The

rule requires a cumulative analysis of

the degree of visibility improvement

that would be achieved in each Class

I area as a result of the emissions

reductions achievable from all sources

subject to BART. The establishment of

BART emission limits must take into

account the cumulative impact overall

from the emissions reductions from

all of the source-specific ‘‘best

technologies’’ identified in the

engineering analysis. Considerations

for this cumulative air quality

analysis are discussed in section V.

—Emission limits. Considering the

engineering analysis and the

cumulative air quality analysis, States

must establish enforceable limits,

including a deadline for compliance,

for each source subject to BART.

Considerations related to these limits

and deadlines are discussed in section

VI.

—Trading program alternative. General

guidance on how to develop an

emissions trading program alternative

to BART is contained in section VII of

the guidance. (Note that more

comprehensive guidance for emission

trading programs generally is

described in Section VII).

Regulatory Text

The proposed regulatory text would

require that States follow the guidelines

for all BART determinations required

under the regional haze rule. We request

public comment on all provisions of the

guidelines and on the accompanying

regulatory text.

III. Revision to 1980 BART Guidelines

for ‘‘Reasonably Attributable’’ Visibility

Impairment

As noted above, the primary purpose

of today’s proposed rule is to provide

BART guidelines for the regional haze

program. In addition, however, we are

making limited revisions to

longstanding guidelines for BART under

the 1980 visibility regulations for

localized visibility impairment that is

‘‘reasonably attributable’’ to one or a few

sources.1 The visibility regulations

require that States must use a 1980

guidelines document when conducting

BART analyses for certain power plants

for reasonably attributable visibility

impairment. The regulatory text for this

requirement is found in 40 CFR

51.302(c)(4)(iii), as follows:

(iii) BART must be determined for fossilfuel fired generating plants having a total

generating capacity in excess of 750

megawatts pursuant to ‘‘Guidelines for

Determining Best Available Retrofit

Technology for Coal-fired Power Plants and

Other Existing Stationary Facilities’’ (1980),

which is incorporated by reference, exclusive

of appendix E, which was published in the

Federal Register on February 6, 1980 (45 FR

8210). It is EPA publication No. 450/3–80–

009b and is for sale from the U.S. Department

of Commerce, National Technical

Information Service, 5285 Port Royal Road,

Springfield, Virginia 22161. It is also

available for inspection at the Office of the

Federal Register Information Center, 800

North Capitol NW., suite 700, Washington,

DC.

While the analytical process set forth

in these guidelines is still generally

acceptable for conducting BART

analyses for ‘‘reasonably attributable’’

visibility impairment, there are

statements in the 1980 BART Guidelines

that could be read to indicate that the

new source performance standards

(NSPS) may be considered to represent

the maximum achievable control for

existing sources. While this may have

been the case in 1980 (e.g., the NSPS for

sulfur dioxide (SO2) from boilers had

been recently issued in June 1979), the

maximum achievable control levels for

recent plant retrofits have exceeded

NSPS levels. Thus, in order to ensure

that there is no confusion regarding how

the 1980 guidelines should be

interpreted, EPA has included the

following discussion in today’s action

and proposes limited clarifying changes

to the visibility regulations.

In various sections of the 1980

guideline, the discussion indicates that

the NSPS in 1980 was considered to

generally represent the most stringent

option these sources could install as

BART (i.e., maximum achievable level

of control). See, e.g., 1980 BART

Guidelines at pp. 8, 11 and 21. For

example, a flowchart in the 1980

guidelines indicates that if States

establish a BART emission limitation

equivalent to NSPS for the source, then

the State would not need to conduct a

full-blown analysis of control

alternatives. See, 1980 BART Guidelines

at p. 8. Similarly, the visibility analysis

described in the guideline assumes as a

starting point the level of controls

currently achieved by the NSPS. See,

1980 Guideline at p. 11. In the 20-year

period since these guidelines were

developed, there have been advances in

SO2 control technologies that have

significantly increased the level of

control that is feasible, while costs per

ton of SO2 controlled have declined.

38110 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

2U.S. Environmental Protection Agency,

Controlling SO2 Emissions: A Review of

Technologies, EPA–600/R–00–093, Office of

Research and Development, National Risk

Management Research Laboratory, Research

Triangle Park, NC, October 2000, pp 32–34.

3Note also that part II of the 1980 BART

guidelines includes an analysis of 90 percent

control for three power plants burning low-sulfur

coal.

This is demonstrated by a number of

recent retrofits or binding agreements to

retrofit coal-fired power plants in the

western United States. These plants

include: Hayden (CO), Navajo (AZ),

Centralia (WA), and Mohave (NV).

These cases have shown that control

options exist which can achieve a

significantly greater degree of control

than the 70 percent minimum required

by the NSPS for power plants emitting

SO2 at less than 0.60 lb/million Btu heat

input. These retrofits have achieved, or

are expected to achieve, annual SO2

reductions in the 85 to 90 percent range.

Additionally, an EPA report 2 published

in October 2000 shows that the SO2

removal for flue gas desulfurization

systems installed in the 1990s is

commonly 90 percent or more for both

wet and dry scrubbers, well above the

minimum 70 percent control required

by the 1979 NSPS.3

Given the advances in control

technology that have occurred over the

past 20 years, we believe that it should

be made clear that the BART analyses

for reasonably attributable visibility

impairment should not be based on an

assumption that the NSPS level of

control represents the maximum

achievable level of control. While it is

possible that a detailed analysis of the

BART factors could result in the

selection of a NSPS level of control, we

believe that States should only reach

this conclusion based upon an analysis

of the full range of control options,

including those more stringent than a

NSPS level of control. In sum, all

‘‘reasonably attributable’’ BART

analyses should consider control levels

more stringent than NSPS, including

maximum achievable levels, and

evaluate them in light of the statutory

factors.

IV. Administrative Requirements

In preparing any proposed rule, EPA

must meet the administrative

requirements contained in a number of

statutes and executive orders. In this

section of the preamble, we discuss how

today’s regulatory proposal for BART

guidelines addresses these

administrative requirements.

A. Regulatory Planning and Review by

the Office of Management and Budget

(OMB) (Executive Order 12866)

Under Executive Order 12866 (58 FR

51735, October 4, 1993) the Agency

must determine whether the regulatory

action is ‘‘significant’’ and, therefore,

subject to OMB review and the

requirements of the Executive Order.

The Order defines ‘‘significant

regulatory action’’ as one that is likely

to result in a rule that may:

(1) Have an annual effect on the

economy of $100 million or more or

adversely affect in a material way the

economy, a sector of the economy,

productivity, competition, jobs, the

environment, public health or safety, or

State, local, or tribal governments or

communities;

(2) Create a serious inconsistency or

otherwise interfere with an action taken

or planned by another agency;

(3) Materially alter the budgetary

impacts of entitlements, grants, user

fees, or loan programs or the rights and

obligations of recipients thereof; or

(4) Raise novel legal or policy issues

arising out of legal mandates, the

President’s priorities, or the principles

set forth in the Executive Order.

Pursuant to the terms of Executive

Order 12866, it has been determined

that this rule is a ‘‘significant regulatory

action’’ and EPA has submitted it to

OMB for review. The drafts of rules

submitted to OMB, the documents

accompanying such drafts, written

comments thereon, written responses by

EPA, and identification of the changes

made in response to OMB suggestions or

recommendations are available for

public inspection at EPA’s Air and

Radiation Docket and Information

Center (Docket Number A–2000–28).

Because today’s guidelines clarify,

and do not change, the existing rule

requirements of the regional haze rule,

the guidelines do not have any effect on

the Regulatory Impact Analysis (RIA)

that was previously prepared for the

regional haze rule. This RIA is available

in the docket for the regional haze rule

(A–95–38). As part of the analyses

included in this RIA, we provided an

estimate of the potential cost of control

to BART sources that is an average of

the costs associated with the least

stringent illustrative progress goal (1.0

deciview reduction over a 15-year

period) and the most stringent

illustrative progress goal (10 percent

deciview reduction over a 10-year

period). The annual cost of control to

BART sources associated with the final

Regional Haze rulemaking in 2015, the

year for which impacts are projected, is

$72 million (1990 dollars).

This estimate of the control costs for

BART sources for the year 2015 was

calculated after taking into account a

regulatory baseline projection for the

year 2015. The baseline for these

calculations included control measures

estimated to be needed for partial

attainment of the PM and ozone NAAQS

issued in 1997. These baseline estimates

were contained in an analysis prepared

for the RIA for the PM and ozone

NAAQS, and are summarized in the RIA

for the regional haze rulemaking. As a

result, in this RIA, we calculated

relatively small impacts for BART, in

part because the baseline for the

analysis assumed a substantial degree of

emissions control for BART-eligible

sources in response to the national

ambient air quality standards (NAAQS)

for PM2.5.

The EPA provided a benefits analysis

of the emissions reductions associated

with the four illustrative progress goals

in the RIA for the final rulemaking. This

benefits analysis is also incremental to

partial attainment of the PM and ozone

NAAQS issued in 1997. We did not,

however, include a benefits analysis for

the reductions from controls specific to

the potentially affected BART sources.

For more information on the benefit

analysis for the final Regional Haze

rulemaking, please refer to the RIA in

the public docket for the regional haze

rule (Docket A–95–38).

B. Regulatory Flexibility Act

The EPA has determined that it is not

necessary to prepare a regulatory

flexibility analysis in connection with

this proposed rule. The EPA has also

determined that this proposed rule

would not have a significant impact on

a substantial number of small entities

because the rule would not establish

requirements applicable to small

entities.

The Regulatory Flexibility Act (5

U.S.C. 601 et seq.) (RFA), as amended

by the Small Business Regulatory

Enforcement Fairness Act (Pub. L.

No.104–121) (SBREFA), provides that

whenever an agency is required to

publish a general notice of proposed

rulemaking, it must prepare and make

available an initial regulatory flexibility

analysis, unless it certifies that the

proposed rule, if promulgated, will not

have ‘‘a significant economic impact on

a substantial number of small entities.’’

5 U.S.C. 605(b). Courts have interpreted

the RFA to require a regulatory

flexibility analysis only when small

entities will be subject to the

requirements of the rule. See Motor and

Equip. Mfrs. Ass’n v. Nichols, 142 F.3d

449 (D.C. Cir. 1998); United Distribution

Cos. v. FERC, 88 F.3d 1105, 1170 (D.C.

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38111

Cir. 1996); Mid-Tex Elec. Co-op, Inc. v.

FERC, 773 F.2d 327, 342 (D.C. Cir. 1985)

(agency’s certification need only

consider the rule’s impact on entities

subject to the rule).

Similar to the discussion in the

proposed and final regional haze rules,

the proposed BART guidelines would

not establish requirements applicable to

small entities. The proposed rule would

apply to States, not to small entities.

The BART requirements in the regional

haze rule require BART determinations

for a select list of major stationary

sources defined by section 169A(g)(7) of

the CAA. However, as noted in the

proposed and final regional haze rules,

the State’s determination of BART for

regional haze involves some State

discretion in considering a number of

factors set forth in section 169A(g)(2),

including the costs of compliance.

Further, the final regional haze rule

allows States to adopt alternative

measures in lieu of requiring the

installation and operation of BART at

these major stationary sources. As a

result, the potential consequences of the

BART provisions of the regional haze

rule (as clarified in today’s proposed

guidelines) at specific sources are

speculative. Any requirements for BART

will be established by State

rulemakings. The States would

accordingly exercise substantial

intervening discretion in implementing

the BART requirements of the regional

haze rule and today’s proposed

guidelines. In addition, we note that

most sources potentially affected by the

BART requirements in section 169A of

the CAA are large industrial plants. Of

these, we would expect few, if any, to

be considered small entities. We request

comment on issues regarding small

entities that States might encounter

when implementing the BART

provision.

For today’s proposed BART

guidelines, EPA certifies that the

guidelines and accompanying regulatory

text would not have a significant impact

on a substantial number of small

entities.

C. Paperwork Reduction Act—Impact on

Reporting Requirements

The information collection

requirements in today’s proposal clarify,

but do not modify, the information

collection requirements for BART.

Reporting requirements related to BART

requirements were included in an

Information Collection Request

document that was prepared by EPA

(ICR No. 1813.02) and a copy may be

obtained from Sandy Farmer, by mail at

Collection Strategies Division; U.S. EPA

(2822) 1200 Pennsylvania Avenue, NW.,

Washington, DC 20460, by email at

farmer.sandy@epa.gov, or by calling

(202) 260–2740. A copy may also be

downloaded off the Internet at http://

www.epa.gov/icr. The information

requirements are not effective until

OMB approves them.

Burden means the total time, effort, or

financial resources expended by persons

to generate, maintain, retain, or disclose

or provide information to or for a

Federal agency. This includes the time

needed to review instructions; develop,

acquire, install, and utilize technology

and systems for the purposes of

collecting, validating, and verifying

information, processing and

maintaining information, and disclosing

and providing information; adjust the

existing ways to comply with any

previously applicable instructions and

requirements; train personnel to be able

to respond to a collection of

information; search data sources;

complete and review the collection of

information; and transmit or otherwise

disclose the information.

An agency may not conduct or

sponsor, and a person is not required to

respond to a collection of information

unless it displays a currently valid OMB

control number. The OMB control

numbers for EPA’s regulations are listed

in 40 CFR part 9 and 48 CFR chapter 15.

Comments are requested on the

Agency’s need for this information, the

accuracy of the provided burden

estimates, and any suggested methods

for minimizing respondent burden,

including through the use of automated

collection techniques. Send comments

on the ICR to the Director, Collection

Strategies Division; U.S. Environmental

Protection Agency (2822); 1200

Pennsylvania Ave., NW., Washington,

DC 20460; and to the Office of

Information and Regulatory Affairs,

Office of Management and Budget, 725

17th St., NW., Washington, DC 20503,

marked ‘‘Attention: Desk Officer for

EPA.’’ Include the ICR number in any

correspondence.

D. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates

Reform Act of 1995 (Pub. L. 104–4)

(UMRA), establishes requirements for

Federal agencies to assess the effects of

their regulatory actions on State, local,

and tribal governments and the private

sector. Under section 202 of the UMRA,

2 U.S.C. 1532, EPA generally must

prepare a written statement, including a

cost-benefit analysis, for any proposed

or final rule that ‘‘includes any Federal

mandate that may result in the

expenditure by State, local, and tribal

governments, in the aggregate, or by the

private sector, of $100,000,000 or more

* * * in any one year.’’ A ‘‘Federal

mandate’’ is defined under section

421(6), 2 U.S.C. 658(6), to include a

‘‘Federal intergovernmental mandate’’

and a ‘‘Federal private sector mandate.’’

A ‘‘Federal intergovernmental

mandate,’’ in turn, is defined to include

a regulation that ‘‘would impose an

enforceable duty upon State, local, or

tribal governments,’’ section

421(5)(A)(i), 2 U.S.C. 658 (5)(A)(i),

except for, among other things, a duty

that is ‘‘a condition of Federal

assistance,’’ section 421(5)(A)(i)(I). A

‘‘Federal private sector mandate’’

includes a regulation that ‘‘would

impose an enforceable duty upon the

private sector,’’ with certain exceptions,

section 421(7)(A), 2 U.S.C. 658(7)(A).

Before promulgating an EPA rule for

which a written statement is needed

under section 202 of the UMRA, section

205, 2 U.S.C. 1535, of the UMRA

generally requires EPA to identify and

consider a reasonable number of

regulatory alternatives and adopt the

least costly, most cost-effective, or least

burdensome alternative that achieves

the objectives of the rule.

By proposing to release BART

guidelines and to require their use, EPA

is not directly establishing any

regulatory requirements that may

significantly or uniquely affect small

governments, including tribal

governments. Thus, EPA is not obligated

to develop under section 203 of the

UMRA a small government agency plan.

Further, EPA carried out

consultations with the governmental

entities affected by this rule in a manner

consistent with the intergovernmental

consultation provisions of section 204 of

the UMRA.

The EPA also believes that because

today’s proposal provides States with

substantial flexibility, the proposed rule

meets the UMRA requirement in section

205 to select the least costly and

burdensome alternative in light of the

statutory mandate for BART. The

proposed rule provides States with the

flexibility to establish BART based on

certain criteria, one of which is the costs

of compliance. The proposed rule also

provides States with the flexibility to

adopt alternatives, such as an emissions

trading program, in lieu of requiring

BART. The BART guidelines therefore,

inherently provides for adoption of the

least costly, most cost-effective, or leastburdensome alternative that achieves

the objective of the rule.

The EPA is not reaching a final

conclusion as to the applicability of the

requirements of UMRA to this

rulemaking action. It is questionable

whether a requirement to submit a State

Implementation Plan (SIP) revision

38112 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

constitutes a Federal mandate. The

obligation for a State to revise its SIP

that arises out of sections 110(a), 169A

and 169B of the CAA is not legally

enforceable by a court of law and, at

most, is a condition for continued

receipt of highway funds. Therefore, it

is possible to view an action requiring

such a submittal as not creating any

enforceable duty within the meaning of

section 421(5)(A)(i) of UMRA (2 U.S.C.

658 (5)(A)(i)). Even if it did, the duty

could be viewed as falling within the

exception for a condition of Federal

assistance under section 421(5)(A)(i)(I)

of UMRA (2 U.S.C. 658(5)(A)(i)(I)). As

noted earlier, however, notwithstanding

these issues, the discussion in section 2

and the analysis in chapter 8 of the RIA

constitutes the UMRA statement that

would be required by UMRA if its

statutory provisions applied, and EPA

has consulted with governmental

entities as would be required by UMRA.

Consequently, it is not necessary for

EPA to reach a conclusion as to the

applicability of the UMRA

requirements.

E. Environmental Justice—Executive

Order 12898

Executive Order 12898 requires that

each Federal agency make achieving

environmental justice part of its mission

by identifying and addressing, as

appropriate, disproportionately high

and adverse human health or

environmental effects of its programs,

policies, and activities on minorities

and low-income populations. The

requirements of Executive Order 12898

have been previously addressed to the

extent practicable in the RIA cited

above, particularly in chapters 2 and 9

of the RIA.

F. Protection of Children From

Environmental Health Risks and Safety

Risks—Executive Order 13045

Executive Order 13045: ‘‘Protection of

Children from Environmental Health

Risks and Safety Risks’’ (62 FR 19885,

April 23, 1997) applies to any rule that:

(1) is determined to be ‘‘economically

significant’’ as defined under Executive

Order 12866, and (2) concerns an

environmental health or safety risk that

EPA has reason to believe may have a

disproportionate effect on children. If

the regulatory action meets both criteria,

the Agency must evaluate the

environmental health or safety effects of

the planned rule on children, and

explain why the planned regulation is

preferable to other potentially effective

and reasonably feasible alternatives

considered by the Agency. The EPA

interprets Executive Order 13045 as

applying only to those regulatory

actions that are based on health or safety

risks, such that the analysis required

under section 5–501 of the Order has

the potential to influence the regulation.

The BART guidelines are not subject to

Executive Order 13045 because they do

not establish an environmental standard

intended to mitigate health or safety

risks.

G. Executive Order 13132: Federalism

Executive Order 13132, entitled

Federalism (64 FR 43255, August 10,

1999), requires EPA to develop an

accountable process to ensure

‘‘meaningful and timely input by State

and local officials in the development of

regulatory policies that have federalism

implications.’’ ‘‘Policies that have

federalism implications’’ are defined in

the Executive Order to include

regulations that have ‘‘substantial direct

effects on the States, on the relationship

between the national government and

the States, or on the distribution of

power and responsibilities among the

various levels of government.’’ Under

Section 6 of Executive Order 13132,

EPA may not issue a regulation that has

federalism implications, that imposes

substantial direct compliance costs, and

that is not required by statute, unless

the Federal government provides the

funds necessary to pay the direct

compliance costs incurred by State and

local governments, or EPA consults with

State and local officials early in the

process of developing the proposed

regulation. The EPA also may not issue

a regulation that has federalism

implications and that preempts State

law unless the Agency consults with

State and local officials early in the

process of developing the proposed

regulation.

The EPA concludes that this rule will

not have substantial federalism

implications, as specified in section 6 of

Executive Order 13132 (64 FR 43255,

August 10, 1999), because it will not

directly impose significant new

requirements on State and local

governments, nor substantially alter the

relationship or the distribution of power

and responsibilities between States and

the Federal government.

Although EPA has determined that

section 6 of Executive Order 13132 does

not apply, EPA nonetheless consulted

with a broad range of State and local

officials during the course of developing

this proposed rule. These included

contacts with the National Governors

Association, National League of Cities,

National Conference of State

Legislatures, U. S. Conference of

Mayors, National Association of

Counties, Council of State Governments,

International City/County Management

Association, and National Association

of Towns and Townships.

H. Executive Order 13084: Consultation

and Coordination With Indian Tribal

Governments

On November 6, 2000, the President

issued Executive Order 13175 (65 FR

67249) entitled ‘‘Consultation and

Coordination with Indian Tribal

Governments.’’ Executive Order 13175

took effect on January 6, 2001, and

revokes Executive Order 13084 (Tribal

Consultation) as of that date. The EPA

developed this proposed rule, however,

during the period when EO 13084 was

in effect; thus, EPA addressed tribal

considerations under EO 13084. The

EPA will analyze and fully comply with

the requirements of EO 13175 before

promulgating the final rule.

Under Executive Order 13084, EPA

may not issue a regulation that is not

required by statute that significantly or

uniquely affects the communities of

Indian tribal governments, and that

imposes substantial direct compliance

costs on those communities, unless the

Federal government provides the funds

necessary to pay the direct compliance

costs incurred by the tribal

governments, or EPA consults with

those governments. If EPA complies by

consulting, Executive Order 13084

requires EPA to provide to OMB, in a

separately identified section of the

preamble to the rule, a description of

the extent of EPA’s prior consultation

with representatives of affected tribal

governments, a summary of the nature

of their concerns, and a statement

supporting the need to issue the

regulation. In addition, Executive Order

13084 requires EPA to develop an

effective process permitting elected

officials and other representatives of

Indian tribal governments ‘‘to provide

meaningful and timely input in the

development of regulatory policies on

matters that significantly or uniquely

affect their communities.’’

Today’s proposed rule does not

significantly or uniquely affect the

communities of Indian tribal

governments. This proposed action does

not involve or impose any requirements

that directly affect Indian tribes. Under

EPA’s tribal authority rule, tribes are not

required to implement CAA programs

but, instead, have the opportunity to do

so. Accordingly, the requirements of

section 3(b) of Executive Order 13084

do not apply to this rule.

I. National Technology Transfer and

Advancement Act

Section 12(d) of the National

Technology Transfer and Advancement

Act of 1995 (‘‘NTTAA’’), Pub. L. No.

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38113

4Regulatory Impact Analysis for the Regional

Haze Rule. U.S. EPA, Office of Air Quality Planning

and Standards. April 22, 1999. Unit 6.6.3, pp. 6–

40 through 6–42.

5U.S. Environmental Protection Agency,

Controlling SO2 Emissions: A Review of

Technologies, EPA–600/R–00–093, Office of

Research and Development, National Risk

Management Research Laboratory, Research

Triangle Park, NC, October 2000, pp 32–34.

6Based on wholesale energy prices for the year

2000.

104–113, § 12(d) (15 U.S.C. 272 note)

directs EPA to use voluntary consensus

standards in its regulatory activities

unless to do so would be inconsistent

with applicable law or otherwise

impractical. Voluntary consensus

standards are technical standards (e.g.,

materials specifications, test methods,

sampling procedures, and business

practices) that are developed or adopted

by voluntary consensus standards

bodies. The NTTAA directs EPA to

provide Congress, through OMB,

explanations when the Agency decides

not to use available and applicable

voluntary consensus standards.

This action does not involve technical

standards. Therefore, EPA did not

consider the use of any voluntary

consensus standards.

J. Executive Order 13211. Actions

Concerning Regulations That

Significantly Affect Energy Supply,

Distribution, or Use

Executive Order 13211, ‘‘Actions

Concerning Regulations That

Significantly Affect Energy Supply,

Distribution, or Use’’ (66 FR 28355 (May

22, 2001)), provides that agencies shall

prepare and submit to the Administrator

of the Office of Information and

Regulatory Affairs, Office of

Management and Budget, a Statement of

Energy Effects for certain actions

identified as ‘‘significant energy

actions.’’ Section 4(b) of Executive

Order 13211 defines ‘‘significant energy

actions’’ as ‘‘any action by an agency

(normally published in the Federal

Register) that promulgates or is

expected to lead to the promulgation of

a final rule or regulation, including

notices of inquiry, advance notices of

proposed rulemaking, and notices of

proposed rulemaking: (1)(i) that is a

significant regulatory action under

Executive Order 12866 or any successor

order, and (ii) is likely to have a

significant adverse effect on the supply,

distribution, or use of energy; or (2) that

is designated by the Administrator of

the Office of Information and Regulatory

Affairs as a significant energy action.’’

Under Executive Order 13211, a

Statement of Energy Effects is a detailed

statement by the agency responsible for

the significant energy action relating to:

(i) any adverse effects on energy supply,

distribution, or use including a shortfall

in supply, price increases, and

increased use of foreign supplies)

should the proposal be implemented,

and (ii) reasonable alternatives to the

action with adverse energy effects and

the expected effects of such alternatives

on energy supply, distribution, and use.

While this rulemaking is a ‘‘significant

regulatory action’’ under Executive

Order 12866, EPA has determined that

this rulemaking is not a significant

energy action because it is not likely to

have a significant adverse effect on the

supply, distribution, or use of energy.

As discussed above in Unit IV.A, EPA

provided an estimate of the potential

cost of control to BART sources in the

RIA for the regional haze rule for the

year 2015. As specified in the CAA,

these BART sources include certain

utility steam electric plants and sources

in 25 additional industrial source

categories. In 1999, EPA estimated that

BART would impose additional costs of

$72 million per year (in 1990 dollars) in

2015 on affected utility and industrial

sources.4 It is expected that these

annual costs will be lower in 2015 than

currently projected due to continued

improvements in scrubber operation

and design. Included in the total cost is

an estimate that roughly 35 utility units

built between the years 1962 and 1977

would be required to install additional

control equipment, typically scrubbers.

Consistent with the RIA, we have

looked at the potential energy impacts

associated with scrubbers. About 60

percent of the overall $72 million

estimate, or about $40 million, was a

result of scrubber cost calculations.

These scrubber cost calculations are

based on cost models which determine

three types of costs for scrubbers: (1)

Annualized capital costs, (2) fixed

operation and maintenance costs, and

(3) variable operating and maintenance

costs. The cost models for variable

operating and maintenance costs took

into account the energy needs of the

scrubber, which was assumed to be

2.0% of the electricity generated by a

plant (or approximately 15,000

Megawatt-hours per year (MW–h/yr) for

a 100 MW scrubber).5 Although BART

requirements may also be achieved with

other control strategies and techniques

(such as emission trading, or switching

types of fuels used to produce power),

these scrubber cost calculations can be

used to provide an order of magnitude

estimate of possible energy costs. The

EPA estimates that of the total annual

cost estimate of $40 million for

scrubbers, about 20 to 35 percent, or

about $9 million to $15 million, would

be variable operating and maintenance

costs. The energy costs for the scrubbers

would be some fraction of this $9 to $15

million estimate, which also includes

other elements such as the costs of

reagents and disposal. Applying this

energy use to the roughly 35 utility

units requires a total of 525 million

MW–h/yr, or 0.5 billion Kilowatt-hours/

year (kWh–yr) of energy, which is

valued at $17 million.6

The EPA also believes that an annual

cost of $40 million for the electric utility

sector for the year 2015 and beyond

would not result in significant changes

in electricity or fuel prices, or in

significant changes in the consumption

of energy.

For non-utility sources, the costs of

the BART requirements may result from

installing, operating and maintaining

pollution control equipment or from

other control strategies and techniques.

As with utilities, a fraction of these

costs in some cases would be related to

the energy used to operate the pollution

control equipment, thus increasing the

overall demand for energy and fuels;

however, such impacts are usually a

small fraction of the overall annualized

costs of control equipment. Thus, EPA

believes that the energy costs for nonutility categories would be a relatively

small fraction of the $72 million cost

estimate. The EPA believes that the

overall effects on energy supply and use

for a small fraction of $72 million would

be trivial, and that this would not

significantly affect the price or supply of

energy.

Therefore, we conclude that based on

the analysis above that the BART

requirements of the Regional Haze Rule

will have a minimal impact, if any, on

energy prices, or on the supply,

distribution, or use of energy.

K. Guidelines for BART Determinations

Under the Regional Haze Rule

We are proposing to adopt guidelines

for BART determinations under the

regional haze rule. The guidelines and

areas on which comment is requested

are described below. After we receive

comments on these guidelines, we will

add them to 40 CFR part 51 as

appendix Y.

Guidelines for BART Determinations Under

the Regional Haze Rule

Table of Contents

I. Introduction and Overview

A. What is the purpose of the guidelines?

A. What does the CAA require generally for

improving visibility?

C. What is the BART requirement in the

CAA?

D. What types of visibility problems does

EPA address in its regulations?

38114 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

E. What are the BART requirements in EPA’s

regional haze regulations?

F. Do States have an alternative to imposing

controls on specific facilities?

G. What is included in the guidelines?

H. Who is the target audience for the

guidelines?

II. How To Identify BART-eligible Sources

A. What are the steps in identifying BARTeligible sources?

1. Step 1: Identify emission units in BART

categories

2. Step 2: Identify the start-up dates of

those emission units

3. Step 3: Compare the potential emissions

to the 250 ton/yr cutoff

4. Final step: Identify the emission units

and pollutants that constitute the BARTeligible source.

III. How To Identify Sources ‘‘Subject to

BART’’

A. How can I identify the ‘‘geographic area’’

or ‘‘region’’ that contributes to a given

Class I area?

IV. Engineering Analysis of BART Options

A. What factors must I address in the

Engineering Analysis?

B. How does a BART engineering analysis

compare to a BACT review under the

PSD program?

C. Which pollutants must I address in the

engineering review?

D. What are the five basic steps of a case-bycase BART engineering analysis?

1. Step 1—How do I identify all available

retrofit emission control techniques?

2. Step 2—How do I determine whether the

options identified in Step 1 are

technically feasible?

a. In general, what do we mean by

technical feasibility?

b. What do we mean by ‘‘available’’

technology?

c. What do we mean by ‘‘applicable’’

technology?

d. What type of demonstration is required

if I conclude that an option is not

technically feasible?

3. Step 3—How do I develop a ranking of

the technically feasible alternatives?

a. What are the appropriate metrics for

comparison?

b. How do I evaluate control techniques

with a wide range of emission

performance levels?

c. How do I rank the control options?

4. Step 4—For a BART engineering

analysis, what impacts must I calculate

and report? What methods does EPA

recommend for the impacts analyses?

a. Impact analysis part 1: how do I estimate

the costs of control?

b. How do I take into account a project’s

‘‘remaining useful life’’ in calculating

control costs?

c. What do we mean by cost effectiveness?

d. How do I calculate average cost

effectiveness?

e. How do I calculate baseline emissions?

f. How do I calculate incremental cost

effectiveness?

g. What other information should I provide

in the cost impacts analysis?

h. Impact analysis part 2: How should I

analyze and report energy impacts?

i. Impact analysis part 3: How do I analyze

‘‘non-air quality environmental

impacts?’’

j. What are examples of non-air quality

environmental impacts?

5. Step 5—How do I select the ‘‘best’’

alternative, using the results of steps 1

through 4?

a. Summary of the impacts analysis

b. Selecting a ‘‘best’’ alternative

c. In selecting a ‘‘best’’ alternative, should

I consider the affordability of controls?

V. Cumulative Air Quality Analysis

A. What air quality analysis do we require in

the regional haze rule for purposes of

BART determinations?

B. How do I consider the results of this

analysis in my selection of BART for

individual sources?

VI. Enforceable Limits / Compliance Date

VII. Emission Trading Program Overview

A. What are the general steps in developing

an emission trading program?

B. What are emission budgets and

allowances?

C. What criteria must be met in developing

an emission trading program as an

alternative to BART?

1. How do I identify sources subject to

BART?

2. How do I calculate the emissions

reductions that would be achieved if

BART were installed and operated on

these sources?

3. For a cap and trade program, how do I

demonstrate that my emission budget

results in emission levels that are

equivalent to or less than the emissions

levels that would result if BART were

installed and operated?

4. How do I ensure that trading budgets

achieve ‘‘greater reasonable progress?’’

5. How do I allocate emissions to sources?

6. What provisions must I include in

developing a system for tracking

individual source emissions and

allowances?

7. How would a regional haze trading

program interface with the requirements

for ‘‘reasonably attributable’’ BART

under § 51.302 of the regional haze rule?

I. Introduction and Overview

A. What Is the Purpose of the

Guidelines?

The Clean Air Act (CAA), in sections

169A and 169B, contains requirements

for the protection of visibility in 156

scenic areas across the United States. To

meet the CAA’s requirements, EPA

recently published regulations to protect

against a particular type of visibility

impairment known as ‘‘regional haze.’’

The regional haze rule is found in this

part (40 CFR part 51), in §§ 51.300

through 51.309. These regulations

require, in § 51.308(e), that certain types

of existing stationary sources of air

pollutants install best available retrofit

technology (BART). The guidelines are

designed to help States and others (1)

identify those sources that must comply

with the BART requirement, and (2)

determine the level of control

technology that represents BART for

each source.

B. What Does the CAA Require

Generally for Improving Visibility?

Section 169A of the CAA, added to

the CAA by the 1977 amendments,

requires States to protect and improve

visibility in certain scenic areas of

national importance. The scenic areas

protected by section 169A are called

‘‘mandatory Class I Federal Areas.’’ In

these guidelines, we refer to these as

‘‘Class I areas.’’ There are 156 Class I

areas, including 47 national parks

(under the jurisdiction of the

Department of Interior—National Park

Service), 108 wilderness areas (under

the jurisdiction of the Department of

Interior–Fish and Wildlife Service or the

Department of Agriculture—US Forest

Service), and one International Park

(under the jurisdiction of the RooseveltCampobello International Commission).

The Federal Agency with jurisdiction

over a particular Class I area is referred

to in the CAA as the Federal Land

Manager. A complete list of the Class I

areas is contained in 40 CFR part 81,

§§ 81.401 through 81.437, and you can

find a map of the Class I areas at the

following internet site: http://

www.epa.gov/ttn/oarpg/t1/fr—notices/

classimp.gif

The CAA establishes a national goal

of eliminating man-made visibility

impairment from the Class I areas where

visibility is an important value. As part

of the plan for achieving this goal, the

visibility protection provisions in the

CAA mandate that EPA issue

regulations requiring that States adopt

measures in their State Implementation

Plans (SIPs), including long-term

strategies, to provide for reasonable

progress towards this national goal. The

CAA also requires States to coordinate

with the Federal Land Managers as they

develop their strategies for addressing

visibility.

C. What Is the BART Requirement in the

CAA?

Under section 169A(b)(2)(A) of the

CAA, States must require certain

existing stationary sources to install

BART. The BART requirement applies

to ‘‘major stationary sources’’ from one

of 26 identified source categories which

have the potential to emit 250 tons per

year or more of any air pollutant. The

CAA requires only sources which were

put in place during a specific 15-year

time interval to install BART. The BART

requirement applies to sources that

existed as of the date of the 1977 CAA

amendments (that is, August 7, 1977)

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38115

1As noted in the preamble to the regional haze

rule, States need not include a BART-eligible source

in the trading program if the source already has

installed BART-level pollution control technology

and the emission limit is a federally enforceable

requirement (64 FR 35742). We clarify in these

guidelines that States may also elect to allow a

source the option of installing BART-level controls

within the 5-year period for compliance with the

BART requirement [see section VI of these

guidelines] rather than participating in a trading

program.

but which had not been in operation for

more than 15 years (that is, not in

operation as of August 7, 1962).

The CAA requires BART when any

source meeting the above description

‘‘emits any air pollutant which may

reasonably be anticipated to cause or

contribute to any impairment of

visibility’’ in any Class I area. In

identifying a level of control as BART,

States are required by section 169A(g) of

the CAA to consider:

—The costs of compliance,

—The energy and non-air quality

environmental impacts of compliance,

—Any existing pollution control

technology in use at the source,

—The remaining useful life of the

source, and

—The degree of visibility improvement

which may reasonably be anticipated

from the use of BART.

The CAA further requires States to make

BART emission limitations part of their

SIPs. As with any SIP revision, this will

be a public process that provides an

opportunity for public comment and

judicial review of any decision by EPA

to approve or disapprove the revision.

D. What Types of Visibility Problems

Does EPA Address in Its Regulations?

The EPA addressed the problem of

visibility in two phases. In 1980, EPA

published regulations addressing what

we termed ‘‘reasonably attributable’’

visibility impairment. Reasonably

attributable visibility impairment is the

result of emissions from one or a few

sources that are generally located in

close proximity to a specific Class I area.

The regulations addressing reasonably

attributable visibility impairment are

published in §§ 51.300 through 51.307.

On July 1, 1999, EPA amended these

regulations to address the second, more

common, type of visibility impairment

known as ‘‘regional haze.’’ Regional

haze is the result of the collective

contribution of many sources over a

broad region. The regional haze rule

regulations slightly modified 40 CFR

51.300 through 51.307, including the

addition of a few definitions in § 51.301,

and added new §§ 51.308 and 51.309.

E. What Are the BART Requirements in

EPA’s Regional Haze Regulations?

In the July 1, 1999 rulemaking, EPA

added a BART requirement for regional

haze. You will find the BART

requirements in 40 CFR 51.308(e)(1).

Definitions of terms used in 40 CFR

51.308(e)(1) are found in § 51.301.

As we discuss in detail in these

guidelines, the regional haze rule

codifies and clarifies the BART

provisions in the CAA. The rule

requires that States identify and list

‘‘BART-eligible sources,’’ that is, that

States identify and list those sources

that fall within one of 26 source

categories, that were put in place during

the 15-year window of time from 1962

to 1977, and that have potential

emissions greater than 250 tons per

year. Once the State has identified the

BART-eligible sources, the next step is

to identify those BART eligible sources

that may ‘‘emit any air pollutant which

may reasonably be anticipated to cause

or contribute to any impairment of

visibility.’’ Under the rule, a source

which fits this description is ‘‘subject to

BART.’’ For each source subject to

BART, States must identify the level of

control representing BART based upon

the following analyses:

— First, paragraph 308(e)(1)(ii)(A)

provides that States must identify the

best system of continuous emission

control technology for each source

subject to BART taking into account

the technology available, the costs of

compliance, the energy and non-air

quality environmental impacts of

compliance, any pollution control

equipment in use at the source, and

the remaining useful life of the

source.

— Second, paragraph 308(e)(1)(ii)(B),

provides that States must conduct an

analysis of the degree of visibility

improvement that would be achieved

from all sources subject to BART that

are within a geographic area that

contributes to visibility impairment in

any protected Class I area.

Once a State has identified the level

of control representing BART (if any), it

must establish an emission limit

representing BART and must ensure

compliance with that requirement no

later than 5 years after EPA approves the

SIP. States are allowed to establish

design, equipment, work practice or

other operational standards when

limitations on measurement

technologies make emission standards

infeasible.

F. Do States Have an Alternative to

Imposing Controls on Specific

Facilities?

States are given the option under 40

CFR 51.308(e)(2) to adopt an alternative

approach to imposing controls on a

case-by-case basis for each source

subject to BART. However, while States

may instead adopt alternative measures,

such as an emissions trading program,

40 CFR 51.308(e)(2)(i) requires States to

provide a demonstration that any such

alternative will achieve greater

‘‘reasonable progress’’ than would have

resulted from installation of BART from

all sources subject to BART. Such a

demonstration must include:

— a list of all BART-eligible sources;

— an analysis of the best system of

continuous emission control

technology available for all sources

subject to BART, taking into account

the technology available, the costs of

compliance, the energy and non-air

quality environmental impacts of

compliance, any pollution control

equipment in use at the source, and

the remaining useful life of the

source. Unlike the analysis for BART

under 40 CFR 51.308(e)(1), which

requires that these factors be

considered on a case-by-case basis,

States may consider these factors on

a category-wide basis, as appropriate,

in evaluating alternatives to BART;

— an analysis of the degree of visibility

improvement that would result from

the alternative program in each

protected Class I area.

States must make sure that a trading

program or other such measure includes

all BART-eligible sources, unless a

source has installed BART, or plans to

install BART consistent with

51.308(e)(1).1 A trading program also

may include additional sources. 40 CFR

51.308(e)(2) also requires that States

include in their SIPs details on how

they would implement the emission

trading program or other alternative

measure. States must provide a detailed

description of the program including

schedules for compliance, the emissions

reductions that they will require, the

administrative and technical procedures

for implementing the program, rules for

accounting and monitoring emissions,

and procedures for enforcement.

G. What Is Included in the Guidelines?

In the guidelines, we provide

procedures States must use in

implementing the regional haze BART

requirements on a source-by-source

basis, as provided in 40 CFR

51.308(e)(1). We address general topics

related to development of a trading

program or other alternative allowed by

40 CFR 51.308(e)(2), but we will address

most of the details of guidance for

trading programs in separate guidelines.

The BART analysis process, and the

contents of this guidance, are as follows:

38116 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

2 In order to account for the possibility that

BART-eligible sources could go unrecognized, we

recommend that you adopt requirements placing a

responsibility on source owners to self-identify if

they meet the criteria for BART-eligible sources.

–Identification of all BART-eligible

sources. Section II of this guidance

outlines a step-by-step process for

identifying BART-eligible sources.

–Identification of sources subject to

BART. As noted above, sources

‘‘subject to BART’’ are those BARTeligible sources which ‘‘emit a

pollutant which may reasonably be

anticipated to cause or contribute to

any impairment of visibility in any

Class I area.’’ We discuss

considerations for identifying sources

subject to BART in section III of the

guidance.

–Engineering analysis. For each source

subject to BART, the next step is to

conduct an engineering analysis of

emissions control alternatives. This

step requires the identification of

available, technically feasible, retrofit

technologies, and for each technology

identified, analysis of the cost of

compliance, and the energy and nonair quality environmental impacts,

taking into account the remaining

useful life and existing control

technology present at the source. For

each source, a ‘‘best system of

continuous emission reduction’’ will

be selected based upon this

engineering analysis. Guidelines for

the engineering analysis are described

in section IV of this guidance.

—Cumulative air quality analysis. The

rule requires a cumulative analysis of

the degree of visibility improvement

that would be achieved in each Class

I area as a result of the emissions

reductions achievable from all sources

subject to BART. The establishment of

BART emission limits must take into

account the cumulative impact overall

from the emissions reductions from

all of the source-specific ‘‘best

technologies’’ identified in the

engineering analysis. Considerations

for this cumulative air quality

analysis are discussed in section V of

this guidance.

—Emissions limits. Considering the

engineering analysis and the

cumulative air quality analysis, States

must establish enforceable limits,

including a deadline for compliance,

for each source subject to BART.

Considerations related to these limits

and deadlines are discussed in section

VI of the guidance.

—Considerations in establishing a

trading program alternative. General

guidance on how to develop an

emissions trading program alternative

is contained in section VII of the

guidance.

H. Who Is the Target Audience for the

Guidelines?

The guidelines are written primarily

for the benefit of State, local and tribal

agencies to satisfy the requirements for

including the BART determinations and

emission limitations in their SIPs or

tribal implementation plans (TIPs).

Throughout the guidelines, which are

written in a question and answer format,

we ask questions ‘‘How do I * * *?’’

and answer with phrases ‘‘you should

* * *, you must* * *’’ The ‘‘you’’

means a State, local or tribal agency

conducting the analysis.2 We recognize,

however, that agencies may prefer to

require source owners to assume part of

the analytical burden, and that there

will be differences in how the

supporting information is collected and

documented.

II. How To Identify BART-Eligible

Sources

This section provides guidelines on

how you identify BART-eligible sources.

A BART-eligible source is an existing

stationary source in 26 listed categories

which meets criteria for startup dates

and potential emissions.

A. What Are the Steps In Identifying

BART-Eligible Sources?

Figure 1 shows the steps for

identifying whether the source is a

‘‘BART eligible source:’’

Step 1: Identify the emission units in

BART categories,

Step 2: Identify the start-up dates of

those emission units, and

Step 3: Compare the potential

emissions to the 250 ton/yr cutoff.

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38117

1. Step 1: Identify Emission Units in the

BART Categories

The BART requirement only applies

to sources in specific categories listed in

the CAA. The BART requirement does

not apply to sources in other source

categories, regardless of their emissions.

The listed categories are:

(1) Fossil-fuel fired steam electric

plants of more than 250 million British

thermal units (BTU) 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,

38118 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

(20) Secondary metal production

facilities,

(21) Chemical process plants,

(22) Fossil-fuel boilers of more than

250 million BTUs 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, and

(26) Charcoal production facilities.

Some plant locations may have

emission units from more than one

category, and some emitting equipment

may fit into more than one category.

Examples of this situation are sulfur

recovery plants at petroleum refineries,

coke oven batteries and sintering plants

at steel mills, and chemical process

plants at refineries. For Step 1, you

identify all of the emissions units at the

plant that fit into one or more of the

listed categories. You do not identify

emission units in other categories.

Example: A mine is collocated with a

electric steam generating unit and a coal

cleaning plant. You would identify emission

units associated with the electric steam

generating unit and the coal cleaning plant,

because they are listed categories but not the

mine, because coal mining is not a listed

category.

The category titles are generally clear

in describing the types of equipment to

be listed. Most of the category titles are

very broad descriptions that encompass

all emission units associated with a

plant site (for example, ‘‘petroleum

refining’’ and ‘‘kraft pulp mills’’). In

addition, this same list of categories

appears in the PSD regulations, for

example in 40 CFR 52.21. States and

source owners need not revisit any

interpretations of the list made

previously for purposes of the PSD

program. We provide the following

clarifications for a few of the category

titles and we request comment on

whether there are any additional source

category titles for which EPA should

provide clarification in the final

guidelines:

—‘‘Steam electric plants of more than

250 million BTU/hr heat input.’’

Because the category refers to

‘‘plants,’’ boiler capacities must be

aggregated to determine whether the

250 million BTU/hr threshold is

reached.

Example: Stationary source includes a

steam electric plant with three 100 million

BTU/hr boilers. Because the aggregate

capacity exceeds 250 million BTU/hr for the

‘‘plant,’’ these boilers would be identified in

Step 2.

‘‘Steam electric plants’’ includes

combined cycle turbines because of

their incorporation of heat recovery

steam generators. Simple cycle turbines

should not be considered ‘‘steam

electric plants’’ because they typically

do not make steam.

—‘‘Fossil-fuel boilers of more than 250

million BTU/hr heat input.’’ The EPA

proposes two options for interpreting

this source category title. The first

option is the approach used in the

regulations for prevention of

significant deterioration (PSD). In the

PSD regulations, this same statutory

language has been interpreted in

regulatory language to mean ‘‘fossil

fuel boilers (or combinations thereof)

totaling more than 250 million British

thermal units per hour heat input.’’

The EPA proposes that this same

interpretation be used for BART as

well. Thus, as in the example above,

you would aggregate boiler capacities

to determine whether the 250 million

BTU/hr threshold is reached.

Under the second option, this

category would be interpreted to cover

only those boilers that are individually

greater than 250 million BTU/hr. This

approach would result in differing

language from the PSD program. It is

possible, however, that different

approaches may be justified. The PSD

program ensures that new source

projects do not circumvent the program

by constructing several boilers with

capacities lower than 250 million BTU/

hr. Because the BART program affects

only sources already in existence as of

the date of the 1977 CAA amendments,

there may be a lesser need to aggregate

boilers that are individually less than

250 million BTU/hr. The EPA requests

comment on both options proposed

above.

—Petroleum storage and transfer

facilities with a capacity exceeding

300,000 barrels. The 300,000 barrel

cutoff refers to total facility-wide tank

capacity for tanks that were put in

place within the 1962–1977 time

period, and includes gasoline and

other petroleum-derived liquids.

—‘‘Phosphate rock processing plants.’’

This category descriptor is broad, and

includes all types of phosphate rock

processing facilities, including

elemental phosphorous plants as well

as fertilizer production plants.

—‘‘Charcoal production facilities.’’ In a

letter sent to EPA on October 11,

2000, the National Association of

Manufacturers (NAM) noted that there

is some limited legislative history on

this source category list. Specifically,

there is discussion in the

Congressional Record from July 29,

1976 (Cong. Record S. 12781–12784)

which identifies a study in the 1970s

by the Research Corporation of New

England (the TRC report). The

Congressional Record contains a table

extracted from the TRC report that

identifies 190 source categories

considered in developing a list of 28

categories that led to the 26 categories

eventually listed in the CAA. In its

October 11, 2000 letter, NAM suggests

that the Congressional Record and the

TRC report are relevant to the

interpretation of the source category

‘‘charcoal production facilities.’’

While EPA does not believe that the

TRC report or table contain any

information that would suggest

subdividing this category, EPA has

included the NAM letter and the cited

passage from the Congressional

Record in the docket for this proposed

rule. The EPA requests comment on

whether and how the information

cited by NAM is relevant to the

interpretation of this or other

categories.

2. Step 2: Identify the Start-Up Dates of

the Emission Units

Emissions units listed under Step 1

are BART-eligible only if they were ‘‘in

existence’’ on August 7, 1977 but were

not ‘‘in operation’’ before August 7,

1962.

What does ‘‘in existence on August 7,

1977’’ mean?

The regulation defines ‘‘in existence’’

to mean that:

The owner or operator has obtained all

necessary preconstruction approvals or

permits required by Federal, State, or local

air pollution emissions and air quality laws

or regulations and either has (1) begun, or

caused to begin, a continuous program of

physical on-site construction of the facility or

(2) entered into binding agreements or

contractual obligations, which cannot be

canceled or modified without substantial loss

to the owner or operator, to undertake a

program of construction of the facility to be

completed in a reasonable time. See 40 CFR

51.301.

Thus, the term ‘‘in existence’’ means the

same thing as the term ‘‘commence

construction’’ as that term is used in the

PSD regulations. See 40 CFR

51.165(a)(1)(xvi) and 40 CFR 52.21(b)(9).

Thus, an emissions unit could be ‘‘in

existence’’ according to this test even if

it did not begin operating until several

years later.

Example: The owner or operator obtained

necessary permits in early 1977 and entered

into binding construction agreements in June

1977. Actual on-site construction began in

late 1978, and construction was completed in

mid-1979. The source began operating in

September 1979. The emissions unit was ‘‘in

existence’’ as of August 7, 1977.

We note that emissions units of this size

for which construction commenced

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38119

3Another possible interpretation would be to

consider sources built before 1962 but modified

during the 1962–1977 time window as a ‘‘new’’

source at the time of the modification. Under this

approach, such sources would be considered to

have commenced operation during the 1962–1977

time period, and thus would be BART eligible.

Similarly, consistent with this interpretation, a

source modified after the 1977 date would be

treated as ‘‘new’’ as of the date of the modification

and therefore would not be BART-eligible. The EPA

believes that this approach may be much more

difficult to implement, given that programs to

identify ‘‘modifications’’ were not in place for much

of the 1962–1977 time period.

AFTER August 7, 1977 (i.e., were not

‘‘in existence’’ on August 7, 1977) were

subject to major new source review

(NSR) under the PSD program. Thus, the

August 7, 1977 ‘‘in existence’’ test is

essentially the same thing as the

identification of emissions units that

were grandfathered from the NSR

review requirements of the 1977 CAA

amendments.

Finally, we note that sources are not

BART eligible if the only change at the

plant was the addition of pollution

controls. For example, if the only

change at a copper smelter during the

1962 through 1977 time period was the

addition of acid plants for the reduction

of SO2 emissions, these emission

controls would not by themselves

trigger a BART review.

What does ‘‘in operation before

August 7, 1962’’ mean?

An emissions unit that meets the

August 7, 1977 ‘‘in existence’’ test is not

BART-eligible if it was in operation

before August 7, 1962. ‘‘In operation’’ is

defined as ‘‘engaged in activity related

to the primary design function of the

source.’’ This means that a source must

have begun actual operations by August

7, 1962 to satisfy this test.

Example: The owner or operator entered

into binding agreements in 1960. Actual onsite construction began in 1961, and

construction was complete in mid-1962. The

source began operating in September 1962.

The emissions unit was not ‘‘in operation’’

before August 7, 1962 and is therefore subject

to BART.

What is a ‘‘reconstructed source?’’

Under a number of CAA programs, an

existing source which is completely or

substantially rebuilt is treated as a new

source. Such ‘‘reconstructed’’ sources

are treated as new sources as of the time

of the reconstruction. Consistent with

this overall approach to reconstructions,

the definition of BART-eligible facility

(reflected in detail in the definition of

‘‘existing stationary facility’’) includes

consideration of sources that were in

operation before August 7, 1962, but

were reconstructed during the August 7,

1962 to August 7, 1977 time period.

Under the regulation, a reconstruction

has taken place if ‘‘the fixed capital cost

of the new component exceeds 50

percent of the fixed capital cost of a

comparable entirely new source.’’ The

rule also states that ‘‘Any final decision

as to whether reconstruction has

occurred must be made in accordance

with the provisions of §§ 60.15 (f)(1)

through (3) of this title.’’ [40 CFR

51.301]. ‘‘§§ 60.15(f)(1) through (3)’’

refers to the general provisions for New

Source Performance Standards (NSPS).

Thus, the same policies and procedures

for identifying reconstructed ‘‘affected

facilities’’ under the NSPS program

must also be used to identify

reconstructed ‘‘stationary sources’’ for

purposes of the BART requirement.

You should identify reconstructions

on an emissions unit basis, rather than

on a plantwide basis. That is, you need

to identify only the reconstructed

emission units meeting the 50 percent

cost criterion. You should include

reconstructed emission units in the list

of emission units you identified in Step

1.

The ‘‘in operation’’ and ‘‘in existence’’

tests apply to reconstructed sources. If

an emissions unit was reconstructed

and began actual operation before

August 7, 1962, it is not BART-eligible.

Similarly, any emissions unit for which

a reconstruction ‘‘commenced’’ after

August 7, 1977, is not BART-eligible.

How are modifications treated under

the BART provision?

The NSPS program and the major

source NSR program both contain the

concept of modifications. In general, the

term ‘‘modification’’ refers to any

physical change or change in the

method of operation of an emissions

unit that leads to an increase in

emissions.

The BART provision in the regional

haze rule contains no explicit treatment

of modifications. Accordingly,

guidelines are needed on how modified

emissions units, previously subject to

best available control technology

(BACT), lowest achievable emission rate

(LAER) and/or NSPS, are treated under

the rule. The EPA believes that the best

interpretation for purposes of the

visibility provisions is that modified

emissions units are still ‘‘existing.’’ The

BART requirements in the CAA do not

appear to provide any exemption for

sources which were modified since

1977. Accordingly, if an emissions unit

began operation before 1962, it is not

BART-eligible if it is modified at a later

date, so long as the modification is not

also a ‘‘reconstruction.’’ Similarly, an

emissions unit which began operation

within the 1962–1977 time window, but

was modified after August 7, 1977, is

BART-eligible. We note, however, that if

such a modification was a major

modification subject to the BACT,

LAER, or NSPS levels of control, the

review process will take into account

that this level of control is already in

place and may find that the level of

controls are already consistent with

BART. The EPA requests comment on

this interpretation for ‘‘modifications.’’ 3

3. Step 3: Compare the potential

emissions to the 250 ton/yr cutoff

The result of Steps 1 and 2 will be a

list of emissions units at a given plant

site, including reconstructed emissions

units, that are within one or more of the

BART categories and that were placed

into operation within the 1962–1977

time window. The third step is to

determine whether the total emissions

represent a current potential to emit that

is greater than 250 tons per year of any

single visibility impairing pollutant. In

most cases, you will add the potential

emissions from all emission units on the

list resulting from Steps 1 and 2. In a

few cases, you may need to determine

whether the plant contains more than

one ‘‘stationary source’’ as the regional

haze rule defines that term, and as we

explain further below.

What pollutants should I address?

Visibility-impairing pollutants

include the following:

—Sulfur dioxide (SO2),

—Nitrogen oxides (NOX),

—Particulate matter. (You may use PM10

as the indicator for particulate matter.

We do not recommend use of total

suspended particulates (TSP). PM10

emissions include the components of

PM2.5 as a subset. There is no need to

have separate 250 ton thresholds for

PM10 and PM2.5, because 250 tons of

PM10 represents at most 250 tons of

PM2.5, and at most 250 tons of any

individual particulate species such as

elemental carbon, crustal material,

etc).

—Volatile organic compounds (VOC),

and

—Ammonia.

What does the term ‘‘potential’’

emissions mean?

The regional haze rule defines

potential to emit as follows:

‘‘Potential to emit’’ means the maximum

capacity of a stationary source to emit a

pollutant under its physical and operational

design. Any physical or operational

limitation on the capacity of the source to

emit a pollutant including air pollution

control equipment and restrictions on hours

of operation or on the type or amount of

material combusted, stored, or processed,

shall be treated as part of its design if the

limitation or the effect it would have on

emissions is federally enforceable. Secondary

emissions do not count in determining the

potential to emit of a stationary source.

38120 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

4Note: Most of these terms and definitions are the

same for regional haze and the 1980 visibility

regulations. For the regional haze rule we use the

term ‘‘BART-eligible source’’ rather than ‘‘existing

stationary facility’’ to clarify that only a limited

subset of existing stationary sources are subject to

BART.

5The EPA recognizes that we are in transition

period from the use of the SIC system to a new

system called the North American industry

Classification System (NAICS). Our initial thinking

is that BART determinations, as a one-time activity,

are perhaps best handled under the SIC

classifications. We request comment on whether a

switch to the new system for the regional haze rule

is warranted—we expect that few if any BART

eligibility determinations would hinge on this

distinction.

6Note: The concept of support facility used for

the PSD program applies here as well. As discussed

in the draft New Source Review Workbook Manual,

October 1990, pages A.3–A.5, support facilities, that

is facilities that convey, store or otherwise assist in

the production of the principal product, must be

grouped with primary facilities even when more

than one 2-digit SIC is present.

This definition is identical to that in the

PSD program (40 CFR 51.166 and

51.18). This means that a source which

actually emits less than 250 tons per

year of a visibility-impairing pollutant is

BART-eligible if its emissions would

exceed 250 tons per year when

operating at its maximum physical and

operational design.

Example: A source, while operating at onefourth of its capacity, emits 75 tons per year

of SO2. If it were operating at 100 percent of

its maximum capacity, the source would emit

300 tons per year. Because under the above

definition such a source would have

‘‘potential’’ emissions that exceed 250 tons

per year, the source (if in a listed category

and built during the 1962–1977 time

window) would be BART-eligible.

A source’s ‘‘potential to emit’’ may take

into account federally enforceable

emission limits.

Example: The same source has a federally

enforceable restriction limiting it to operating

no more than 1⁄2 of the year. Because you can

credit this under the definition of potential

to emit, the source would have a potential of

150 tons per year, which is less than the 250

tons/year cutoff.

The definition of potential to emit

allows only federally enforceable

emission limits to be taken into account

for this purpose, and does not credit

emission limitations which are

enforceable only by State and local

agencies, but not by EPA and citizens in

Federal court. As a result of some court

cases in other CAA programs, EPA is

undertaking a rulemaking to determine

whether only federally enforceable

limits should be taken into account.

This rulemaking will address the

Federal enforceability restriction in the

regional haze definition as well as other

program definitions. We expect that this

rulemaking will be complete well before

the time period for determining whether

BART applies. How do I identify whether a plant has

more than one ‘‘stationary source?’’ The regional haze rule, in 40 CFR

51.301, defines a stationary source as a

‘‘building, structure, facility or

installation which emits or may emit

any air pollutant.’’ 4 The rule further

defines ‘‘building, structure or facility’’

as:

All of the pollutant-emitting activities

which belong to the same industrial

grouping, are located on one or more

contiguous or adjacent properties, and are

under the control of the same person (or

persons under common control). Pollutantemitting activities must be considered as part

of the same industrial grouping if they belong

to the same Major Group (i.e., which have the

same two-digit code) as described in the

Standard Industrial Classification Manual,

1972 as amended by the 1977 Supplement

(U.S. Government Printing Office stock

numbers 4101–0066 and 003–005–00176–0

respectively).

In applying this definition, it is first

necessary to draw the plant boundary,

that is the boundary for the ‘‘contiguous

or adjacent properties.’’ Next, within

this plant boundary it is necessary to

group those emission units that are

under ‘‘common control.’’ The EPA

notes that these plant boundary issues

and ‘‘common control’’ issues are very

similar to those already addressed in

implementation of the title V operating

permits program and in NSR. For emission units within the

‘‘contiguous or adjacent’’ boundary and

under common control, you then group

emission units that are within the same

industrial grouping (that is, associated

with the same 2-digit Standard

Industrial Classification (SIC) code).5

For most plants on the BART source

category list, there will only be one 2-

digit SIC that applies to the entire plant.

For example, all emission units

associated with kraft pulp mills are

within SIC code 26, and chemical

process plants will generally include

emission units that are all within SIC

code 28. You should apply this ‘‘2-digit

SIC test’’ the same way you are now

applying this test in the major source

NSR programs.6

For purposes of the regional haze rule,

you group emissions from all emission

units put in place within the 1962–1977

time period that are within the 2-digit

SIC code, even if those emission units

are in different categories on the BART

category list.

Examples: A chemical plant which started

operations within the 1962 to 1977 time

period manufactures hydrochloric acid

(within the category title ‘‘Hydrochloric,

sulfuric, and nitric acid plants’’) and various

organic chemicals (within the category title

‘‘chemical process plants’’), and has onsite an

industrial boiler greater than 250 million

BTU/hour. All of the emission units are

within SIC 28 and, therefore, all the emission

units are considered in determining BART

eligibility of the plant. You sum the

emissions over all of these emission units to

see whether there are more than 250 tons per

year of potential emissions.

A steel mill which started operations

within the 1962 to 1977 time period includes

a sintering plant, a coke oven battery, and

various other emission units. All of the

emission units are within SIC 33. You sum

the emissions over all of these emission units

to see whether there are more than 250 tons

per year of potential emissions.

4. Final Step: Identify the Emissions

Units and Pollutants That Constitute the

BART-Eligible Source

If the emissions from the list of

emissions units at a stationary source

exceed a potential to emit of 250 tons

per year for any visibility-impairing

pollutant, then that collection of

emissions units is a BART-eligible

source. A BART analysis is required for

each visibility-impairing pollutant

emitted.

Example: A stationary source comprises

the following two emissions units, with the

following potential emissions:

Emissions unit A

500 tons/yr SO2

150 tons/yr NOX

25 tons/yr PM

Emissions unit B

100 tons/yr SO2

75 tons/yr NOX

10 tons/yr PM

For this example, potential emissions of

SO2 are 600 tons per year, which

exceeds the 250 tons/yr threshold.

Accordingly, the entire ‘‘stationary

source’’ that is emissions units A and B

are subject to a BART review for SO2,

NOX, and PM, even though the potential

emissions of PM and NOX each are less

than 250 tons/yr.

Example: The total potential emissions,

obtained by adding the potential emissions of

all emission units in listed categories at a

plant site, are as follows:

200 tons/yr SO2

150 tons/yr NOX

25 tons/yr PM

Even though total emissions exceed 250

tons per year, no individual regulated

pollutant exceeds 250 tons per year and this

source is not BART-eligible.

III. How To Identify Sources ‘‘Subject

To BART’’

After you have identified the BARTeligible sources, the next step is

determining whether these sources are

subject to a further BART analysis

because they emit ‘‘an air pollutant

which may reasonably be anticipated to

cause or contribute’’ to any visibility

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38121

impairment in a Federal Class I area. As

we discuss in the preamble to the

regional haze rule at 64 FR 35739–

35740, the statutory language represents

a very low triggering threshold. In

implementing the regional haze rule,

you should find that a BART-eligible

source is ‘‘reasonably anticipated to

cause or contribute’’ to regional haze if

the source emits pollutants within a

geographic region from which

pollutants can be emitted and

transported downwind to a Class I area.

Where emissions from a given

geographic region contribute to regional

haze in a Class I area, you should

consider any emissions from BARTeligible sources in that region to

contribute to the regional haze problem,

thereby warranting a further BART

analysis for those sources.

A. How Can I Identify ‘‘the Geographic

Area’’ or ‘‘Region’’ That Contributes to

a Given Class I Area?

As noted in the preamble to the

regional haze rule, geographic ‘‘regions’’

that can contribute to regional haze

generally extend for hundreds or

thousands of kilometers (64 FR 35722).

Accordingly, most BART-eligible

sources are located within such a

geographic region. For example, we

believe it would be difficult to

demonstrate that a State or territory’s

emissions do not contribute to regional

haze impairment in a Class I area within

that State or territory.

The regional haze rule recognizes that

there may be geographic areas

(individual States or multi-State areas)

within the United States, (in virtually

all cases involving States that do not

have Class I areas) for which the total

emissions make only a trivial

contribution to visibility impairment in

any Class I area. In identifying any such

State or area, you or a regional planning

organization must conduct an air quality

modeling analysis to demonstrate that

the total emissions from the State or

area makes only a trivial contribution to

visibility impairment in Class I areas.

One approach that can be used is to

determine whether a State or area

contributes in a non-trivial way would

be to do an analysis where you compare

the visibility impairment in a Class I

area with the emissions from a State or

area to the visibility impairment in the

Class I area in the absence of the

emissions from the State or area. This

approach can be referred to as a ‘‘zeroout’’ approach where you zero out the

emissions from the State or area that is

suspected to make a trivial contribution

to visibility impairment in a Class I area.

Under this approach, you would

compare:

(1) the visibility impairment in each

affected Class I area (for the average of

the 20 percent most impaired days and

the 20 percent least impaired days)

when the emissions from the State or

area suspected to have a trivial

contribution are included in the

modeling analysis, and

(2) the visibility impairment in each

affected Class I area (for the average of

the 20 percent most impaired days and

the 20 percent least impaired days),

excluding from the modeling analysis

the emissions from the geographic area

suspected to have a trivial impact.

The difference in visibility between

these two model runs provides an

indication of the impact on visibility of

emissions from the State(s) in question.

In addition, it may be possible in the

future to conduct analyses of the

geographic area that contributes to

visibility impairment in a Class I area

through use of a source apportionment

model for PM. Source apportionment

models for PM are currently under

development by private consultants.

Guidance for regional modeling for

visibility and PM is found in a

document entitled ‘‘Guidance for

Demonstrating Attainment of Air

Quality Goals for PM2.5 and Regional

Haze.’’ [Note: this document is currently

in draft form, but we expect a final

document before final publication of the

BART guidelines]

IV. Engineering Analysis of BART

Options

This section describes the process for

the engineering analysis of control

options for sources subject to BART.

A. What Factors Must I Address in the

Engineering Analysis?

The visibility regulations define

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, the

remaining useful life of the source, and the

degree of improvement in visibility which

may reasonably be anticipated to result from

the use of such technology.

In the regional haze rule, we divide the

BART analysis into two parts: an

engineering analysis requirement in 40

CFR 51.308(e)(1)(ii)(A), and a visibility

impacts analysis requirement in 40 CFR

51.308(e)(1)(ii)(B). This section of the

guidelines address the requirements for

the engineering analysis. Your

engineering analysis identifies the best

system of continuous emission

reduction taking into account:

—The available retrofit control options,

—Any pollution control equipment in

use at the source (which affects the

availability of options and their

impacts),

—The costs of compliance with control

options,

—The remaining useful life of the

facility (which as we will discuss

below, is an integral part of the cost

analysis), and

—The energy and non-air quality

environmental impacts of control

options.

We discuss the requirement for a

visibility impacts analysis below in

section V.

B. How Does a BART Engineering

Analysis Compare to a BACT Review

Under the PSD Program?

In this proposal, we are seeking

comment on two alternative approaches

for conducting a BART engineering

analysis. EPA prefers the first approach.

Under this first alternative, the BART

analysis would be very similar to the

BACT review as described in the New

Source Review Workshop Manual

(Draft, October 1990). Consistent with

the Workshop Manual, the BART

engineering analysis would be a process

which provides that all available control

technologies be ranked in descending

order of control effectiveness. Under

this option, you must first examine the

most stringent alternative. That

alternative is selected as the ‘‘best’’

unless you demonstrate and document

that the alternative cannot be justified

based upon technical considerations,

costs, energy impacts, and non-air

quality environmental impacts. If you

eliminate the most stringent technology

in this fashion, you then consider the

next most stringent alternative, and so

on.

The EPA also requests comment on an

alternative decision-making approach

that would not necessarily begin with

an evaluation of the most stringent

control option. Under this approach,

you would have more choices in the

way you structure your BART analysis.

For example, you could choose to begin

the BART determination process by

evaluating the least stringent technically

feasible control option or an

intermediate control option drawn from

the range of technically feasible control

alternatives. Under this approach, you

would then consider the additional

emission reductions, costs, and other

38122 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

7That is, emission uunits that were in existence

on August 7, 1977 and which began actual

operation on or after August 7, 1962.

8 In identifying ‘‘all’’ options, you must identify

the most stringent option and a reasonable set of

options for analysis that reflects a comprehensive

list of available technologies. 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.

9 In EPA’s 1980 BART guidelines for reasonably

attributable visibility impairment, we concluded

that NSPS standards generally, at that time,

represented the best level sources could install as

BART, and we required no further demonstration if

a NSPS level was selected. In the 20 year period

since this guidance was developed, there have been

advances in SO2 control technologies, confirmed by

a number of recent retrofits at Western power

plants. Accordingly, EPA no longer concludes that

the NSPS level of controls automatically represents

‘‘the best these sources can install.’’ While it is

possible that a detailed analysis of the BART factors

could result in the selection of a NSPS level of

control, we believe that you should only reach this

conclusion based upon an analysis of the full range

of control options.

effects (if any) of successively more

stringent control options. Under such an

approach, you would still be required to

(1) display and rank all of the options

in order of control effectiveness,

including the most stringent control

option, and to identify the average and

incremental costs of each option; (2)

consider the energy and non-air quality

environmental impacts of each option;

and (3) provide a justification for

adopting the control technology that

you select as the ‘‘best’’ level of control,

including an explanation as to why you

rejected other more stringent control

technologies. While both approaches

require essentially the same parameters

and analyses, the EPA prefers the first

approach described above, because we

believe it may be more straightforward

to implement than the alternative and

would tend to give more thorough

consideration to stringent control

alternatives.

Although very similar in process,

BART reviews differ in several respects

from the BACT review process

described in the NSR Draft Manual.

First, because all BART reviews apply to

existing sources, the available controls

and the impacts of those controls may

differ. Second, the CAA requires you to

take slightly different factors into

account in determining BART and

BACT. In a BACT analysis, the

permitting authority must consider the

‘‘energy, environmental and economic

impacts and other costs’’ associated

with a control technology in making its

determination. In a BART analysis, on

the other hand, the State must take into

account the ‘‘cost of compliance, the

remaining useful life of the source, the

energy and nonair quality

environmental impacts of compliance,

any existing pollution control

technology in use at the source, and the

degree of improvement in visibility from

the use of such technology’’ in making

its BART determination. Because of the

differences in terminology, the BACT

review process tends to encompass a

broader range of factors. For example,

the term ‘‘environmental impacts’’ in

the BACT definition is more broad than

the term ‘‘nonair quality environmental

impacts’’ used in the BART definition.

Accordingly, there is no requirement in

the BART engineering analysis to

evaluate adverse air quality impacts of

control alternatives such as the relative

impacts on hazardous air pollutants,

although you may wish to do so.

Finally, for the BART analysis, there is

no minimum level of control required,

while any BACT emission limitation

must be at least as stringent as any

NSPS that applies to the source.

C. Which Pollutants Must I Address in

the Engineering Review?

Once you determine that a source is

subject to BART, then a BART review is

required for each visibility-impairing

pollutant emitted. In a BART review, for

each affected emission unit, you must

establish BART for each pollutant that

can impair visibility. Consequently, the

BART determination must address air

pollution control measures for each

emissions unit or pollutant emitting

activity subject to review.

Example: Plantwide emissions from

emission units within the listed categories

that began operation within the ‘‘time

window’’ for BART7 are 300 tons per year of

NOX, 200 tons per year of SO2, and 150 tons

of primary particulate. Emissions unit A

emits 200 tons per year of NOX, 100 tons per

year of SO2, and 100 tons per year of primary

particulate. Other emission units, units B

through H, which began operating in 1966,

contribute lesser amounts of each pollutant.

For this example, a BART review is required

for NOX, SO2, and primary particulate, and

control options must be analyzed for units B

through H as well as unit A.

D. What Are the Five Basic Steps of a

Case-by-Case BART Engineering

Analysis?

The five steps are:

Step 1—Identify all 8 available retrofit

control technologies,

Step 2—Eliminate Technically

Infeasible Options,

Step 3—Rank Remaining Control

Technologies By Control

Effectiveness,

Step 4—Evaluate Impacts and

Document the Results, and

Step 5—Select ‘‘Best System of

Continuous Emission Reduction.’’

1. Step 1: How Do I Identify All

Available Retrofit Emission Control

Techniques?

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 evaluation. Air

pollution control technologies can

include a wide variety of available

methods, systems, and techniques for

control of the affected pollutant.

Available air pollution control

technologies can include technologies

employed outside of the United States

that have been successfully

demonstrated in practice on full scale

operations, particularly those that have

been demonstrated as retrofits to

existing sources. Technologies required

as BACT or LAER are available for

BART purposes and must be included

as control alternatives. The control

alternatives should 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 and 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

already been demonstrated in practice.

Where a NSPS exists for a source

category (which is the case for most of

the categories affected by BART), you

should include a level of control

equivalent to the NSPS as one of the

control options.9 The NSPS standards

are codified in 40 CFR part 60. We note

that there are situations where NSPS

standards do not require the most

stringent level of available control for all

sources within a category. For example,

post-combustion NOX controls (the most

stringent controls for stationary gas

turbines) are not required under subpart

GG of the NSPS for Stationary Gas

Turbines. However, such controls must

still be considered available

technologies for the BART selection

process.

Potentially applicable retrofit control

alternatives can be categorized in three

ways.

• Pollution prevention: use of

inherently lower-emitting processes/

practices, including the use of materials

and production processes and work

practices that prevent emissions and

result in lower ‘‘production-specific’’

emissions,

• Use of, (and where already in place,

improvement in the performance of)

add-on controls, such as scrubbers,

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38123

10Because BART applies to existing sources, we

recognize that there will probably be far fewer

opportunities to consider inherently lower-emitting

processes than for NSR.

fabric filters, thermal oxidizers and

other devices that control and reduce

emissions after they are produced, and

• Combinations of inherently loweremitting processes and add-on controls.

Example: for a gas-fired turbine, a

combination of combustion controls (an

inherently lower-emitting process) and

post-combustion controls such as

selective catalytic reduction (add-on)

may be available to reduce NOX

emissions.

For the engineering analysis, you

should consider potentially applicable

control techniques from all three

categories. You should consider lowerpolluting processes based on

demonstrations from facilities

manufacturing identical or similar

products from identical or similar raw

materials or fuels. Add-on controls, on

the other hand, should be considered

based on the physical and chemical

characteristics of the pollutant-bearing

emission stream. Thus, candidate addon controls may have been applied to a

broad range of emission unit types that

are similar, insofar as emissions

characteristics, to the emissions unit

undergoing BART review.

In the course of the BART engineering

analysis, one or more of the available

control options may be eliminated from

consideration because they are

demonstrated to be technically

infeasible or to have unacceptable

energy, cost, or non-air quality

environmental impacts on a case-bycase (or site-specific) basis. However, at

the outset, you should initially identify

all control options with potential

application to the emissions unit under

review.

We do not consider BART as a

requirement to redesign the source

when considering available control

alternatives. For example, where the

source subject to BART is a coal-fired

electric generator, we do not require the

BART analysis to consider building a

natural gas-fired electric turbine

although the turbine may be inherently

less polluting on a per unit basis.

In some cases, retrofit design changes

may be available for making a given

production process or emissions unit

inherently less polluting.10 (Example:

To allow for use of natural gas rather

than oil for startup). In such cases, the

ability of design considerations to make

the process inherently less polluting

must be considered as a control

alternative for the source.

Combinations of inherently lowerpolluting processes/practices (or a

process made to be inherently less

polluting) and add-on controls could

possibly yield more effective means of

emissions control than either approach

alone. Therefore, the option to use an

inherently lower-polluting process does

not, in and of itself, mean that no

additional add-on controls need to be

included in the BART analysis. These

combinations should be identified in

Step 1 for evaluation in subsequent

steps.

For emission units subject to a BART

engineering review, there will often be

control measures or devices already in

place. For such emission units, it is

important to include control options

that involve improvements to existing

controls, and not to limit the control

options only to those measures that

involve a complete replacement of

control devices.

Example: For a power plant with an

existing wet scrubber, the current control

efficiency is 66 percent. Part of the reason for

the relatively low control efficiency is that 22

percent of the gas stream bypasses the

scrubber. An engineering review identifies

options for improving the performance of the

wet scrubber by redesigning the internal

components of the scrubber and by

eliminating or reducing the percentage of the

gas stream that bypasses the scrubber. Four

control options are identified: (1) 78 percent

control based upon improved scrubber

performance while maintaining the 22

percent bypass, (2) 83 percent control based

upon improved scrubber performance while

reducing the bypass to 15 percent, (3) 93

percent control based upon improving the

scrubber performance while eliminating the

bypass entirely, (this option results in a ‘‘wet

stack’’ operation in which the gas leaving the

stack is saturated with water) and (4) 93

percent as in option 3, with the addition of

an indirect reheat system to reheat the stack

gas above the saturation temperature. You

must consider each of these four options in

a BART analysis for this source.

You are expected to identify all

demonstrated and potentially applicable

retrofit control technology alternatives.

Examples of general information sources

to consider include:

• The EPA’s Clean Air Technology

Center, which includes the RACT/

BACT/LAER Clearinghouse (RBLC);

• State and Local Best Available

Control Technology Guidelines—many

agencies have online information—for

example South Coast Air Quality

Management District, Bay Area Air

Quality Management District, and Texas

Natural Resources Conservation

Commission;

• Control technology vendors;

• Federal/State/Local NSR permits

and associated inspection/performance

test reports;

• Environmental consultants;

• Technical journals, reports and

newsletters, air pollution control

seminars; and

• EPA’s NSR bulletin board—http://

www.epa.gov/ttn/nsr;

• Department of Energy’s Clean Coal

Program—technical reports;

• NOX Control Technology ‘‘Cost

Tool’’—Clean Air Markets Division web

page—http://www.epa.gov/acidrain/

nox/noxtech.htm;

• Performance of selective catalytic

reduction on coal-fired steam generating

units—final report. OAR/ARD, June

1997 (also available at

http:www.epa.gov/acidrain/nox/

noxtech.htm);

• Cost estimates for selected

applications of NOX control

technologies on stationary combustion

boilers. OAR/ARD June 1997. (Docket

for NOX SIP call, A–96–56, II–A–03);

• Investigation of performance and

cost of NOX controls as applied to group

2 boilers. OAR/ARD, August 1996.

(Docket for Phase II NOX rule, A–95–28,

IV–A–4);

• Controlling SO2 Emissions: A

Review of Technologies. EPA–600/R–

00–093, USEPA/ORD/NRMRL, October

2000.

• OAQPS Control Cost Manual.

You should compile appropriate

information from all available

information sources, and you should

ensure that the resulting list of control

alternatives is complete and

comprehensive.

2. Step 2: How Do I Determine Whether

the Options Identified in Step 1 Are

Technically Feasible?

In Step two, you evaluate the

technical feasibility of the control

options you identified in Step one. You

should clearly document a

demonstration of technical infeasibility

and should show, based on physical,

chemical, and engineering principles,

that technical difficulties would

preclude the successful use of the

control option on the emissions unit

under review. You may then eliminate

such technically infeasible control

options from further consideration in

the BART analysis.

In general, what do we mean by

technical feasibility?

Control technologies are technically

feasible if either (1) they have been

installed and operated successfully for

the type of source under review, or (2)

the technology could be applied to the

source under review. Two key concepts

are important in determining whether a

technology could be applied:

‘‘availability’’ and ‘‘applicability.’’ As

explained in more detail below, a

technology is considered ‘‘available’’ if

38124 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

the source owner may obtain it through

commercial channels, or it is otherwise

available within the common sense

meaning of the term. An available

technology is ‘‘applicable’’ if it can

reasonably be installed and operated on

the source type under consideration. A

technology that is available and

applicable is technically feasible.

What do we mean by ‘‘available’’

technology?

The typical stages for bringing a

control technology concept to reality as

a commercial product are:

• Concept stage;

• Research and patenting;

• Bench scale or laboratory testing;

• Pilot scale testing;

• Licensing and commercial

demonstration; and

• Commercial sales.

A control technique is considered

available, within the context presented

above, if it has reached the licensing

and commercial sales stage of

development. Similarly, we 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. Consequently,

you would not consider technologies in

the pilot scale testing stages of

development as ‘‘available’’ for

purposes of BART review.

Commercial availability by itself,

however, is not necessarily a sufficient

basis for concluding a technology to be

applicable and therefore technically

feasible. Technical feasibility, as

determined in Step 2, also means a

control option may reasonably be

deployed on or ‘‘applicable’’ to the

source type under consideration.

Because a new technology may

become available at various points in

time during the BART analysis process,

we believe that guidelines are needed

on when a technology must be

considered. For example, a technology

may become available during the public

comment period on the State’s rule

development process. Likewise, it is

possible that new technologies may

become available after the close of the

State’s public comment period and

before submittal of the SIP to EPA, or

during EPA’s review process on the SIP

submittal. In order to provide certainty

in the process, we propose that all

technologies be considered if available

before the close of the State’s public

comment period. You need not consider

technologies that become available after

this date. As part of your analysis, you

should consider any technologies

brought to your attention in public

comments. If you disagree with public

comments asserting that the technology

is available, you should provide an

explanation for the public record as to

the basis for your conclusion.

What do we mean by ‘‘applicable’’

technology?

You need to exercise technical

judgment in determining whether a

control alternative is applicable to the

source type under consideration. In

general, a commercially available

control option will be presumed

applicable if it has been or is soon to be

deployed (e.g., is specified in a permit)

on the same or a similar source type.

Absent a showing of this type, you

evaluate technical feasibility by

examining the physical and chemical

characteristics of the pollutant-bearing

gas stream, and comparing them to the

gas stream characteristics of the source

types to which the technology had been

applied previously. Deployment of the

control technology on a new or existing

source with similar gas stream

characteristics is generally a sufficient

basis for concluding the technology is

technically feasible barring a

demonstration to the contrary as

described below.

What type of demonstration is

required if I conclude that an option is

not technically feasible?

Where you assert that a control option

identified in Step 1 is technically

infeasible, you should make a factual

demonstration that the option is

commercially unavailable, or that

unusual circumstances preclude its

application to a particular emission

unit. Generally, such a demonstration

involves an evaluation of the

characteristics of the pollutant-bearing

gas stream and the capabilities of the

technology. Alternatively, a

demonstration of technical infeasibility

may involve a showing that there are

unresolvable technical difficulties with

applying the control to the source (e.g.,

size of the unit, location of the proposed

site, or operating problems related to

specific circumstances of the source).

Where the resolution of technical

difficulties is a matter of cost, you

should consider the technology to be

technically feasible. The cost of a

control alternative is considered later in

the process.

The determination of technical

feasibility is sometimes influenced by

recent air quality permits. In some

cases, an air quality permit may require

a certain level of control, but the level

of control in a permit is not expected to

be achieved in practice (e.g., a source

has received a permit but the project

was canceled, or every operating source

at that permitted level has been

physically unable to achieve

compliance with the limit). Where this

is the case, you should provide

supporting documentation showing why

such limits are not technically feasible,

and, therefore, why the level of control

(but not necessarily the technology) may

be eliminated from further

consideration. However, if there is a

permit requiring the application of a

certain technology or emission limit to

be achieved for such technology

(especially as a retrofit for an existing

emission unit), this usually is sufficient

justification for you to assume the

technical feasibility of that technology

or emission limit.

Physical modifications needed to

resolve technical obstacles do not, in

and of themselves, provide a

justification for eliminating the control

technique on the basis of technical

infeasibility. However, you may

consider the cost of such modifications

in estimating costs. This, in turn, may

form the basis for eliminating a control

technology (see later discussion).

Vendor guarantees may provide an

indication of commercial availability

and the technical feasibility of a control

technique and could contribute to a

determination of technical feasibility or

technical infeasibility, depending on

circumstances. However, we do not

consider a vendor guarantee alone to be

sufficient justification that a control

option will work. Conversely, lack of a

vendor guarantee by itself does not

present sufficient justification that a

control option or an emissions limit is

technically infeasible. Generally, you

should make decisions about technical

feasibility based on chemical, and

engineering analyses (as discussed

above), in conjunction with information

about vendor guarantees.

A possible outcome of the BART

procedures discussed in these

guidelines is the evaluation of multiple

control technology alternatives which

result in essentially equivalent

emissions. It is not EPA’s intent to

encourage evaluation of unnecessarily

large numbers of control alternatives for

every emissions unit. Consequently, you

should use judgment in deciding on

those alternatives for which you will

conduct the detailed impacts analysis

(Step 4 below). For example, if two or

more control techniques result in

control levels that are essentially

identical, considering the uncertainties

of emissions factors and other

parameters pertinent to estimating

performance, you may evaluate only the

less costly of these options. You should

narrow the scope of the BART analysis

in this way, only if there is a negligible

difference in emissions and energy and

non-air quality environmental impacts

between control alternatives.

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38125

3. Step 3: How Do I Develop a Ranking

of the Technically Feasible

Alternatives?

Step 3 involves ranking all the

technically feasible control alternatives

identified in Step 2. For the pollutant

and emissions unit under review, you

rank the control alternatives from the

most to the least effective in terms of

emission reduction potential.

Two key issues that must be

addressed in this process include:

(1) Making sure that you express the

degree of control using a metric that

ensures an ‘‘apples to apples’’

comparison of emissions performance

levels among options, and

(2) Giving appropriate treatment and

consideration of control techniques that

can operate over a wide range of

emission performance levels.

In some instances, a control technology

may reduce more than one visibility

impairing pollutant. We request

comment on whether and how the

BART guidelines should address the

process for ranking such control

technologies against control

technologies which reduce emissions of

only one pollutant.

What are the appropriate metrics for

comparison?

This issue is especially important

when you compare inherently lowerpolluting processes to one another or to

add-on controls. In such cases, it is

generally most effective to express

emissions performance as an average

steady state emissions level per unit of

product produced or processed.

Examples of common metrics:

• Pounds of SO2 emissions per

million Btu heat input, and

• Pounds of NOX emissions per ton of

cement produced.

How do I evaluate control techniques

with a wide range of emission

performance levels?

Many control techniques, including

both add-on controls and inherently

lower polluting processes, can perform

at a wide range of levels. Scrubbers and

high and low efficiency electrostatic

precipitators (ESPs) are two of the many

examples of such control techniques

that can perform at a wide range of

levels. It is not our intent to require

analysis of each possible level of

efficiency for a control technique, as

such an analysis would result in a large

number of options. It is important,

however, that in analyzing the

technology you take into account the

most stringent emission control level

that the technology is capable of

achieving. You should use the most

recent regulatory decisions and

performance data (e.g., manufacturer’s

data, engineering estimates and the

experience of other sources) to identify

an emissions performance level or levels

to evaluate.

In assessing the capability of the

control alternative, latitude exists to

consider any special circumstances

pertinent to the specific source under

review, or regarding the prior

application of the control alternative.

However, you must document the basis

for choosing the alternate level (or

range) of control in the BART analysis.

Without a showing of differences

between the source and other sources

that have achieved more stringent

emissions limits, you should conclude

that the level being achieved by those

other sources is representative of the

achievable level for the source being

analyzed.

You may encounter cases where you

may wish to evaluate other levels of

control in addition to the most stringent

level for a given device. While you must

consider the most stringent level as one

of the control options, you may consider

less stringent levels of control as

additional options. This would be

useful, particularly in cases where the

selection of additional options would

have widely varying costs and other

impacts.

Finally, we note that for retrofitting

existing sources in addressing BART,

you should consider ways to improve

the performance of existing control

devices, particularly when a control

device is not achieving the level of

control that other similar sources are

achieving in practice with the same

device.

How do I rank the control options?

After determining the emissions

performance levels (using appropriate

metrics of comparison) for each control

technology option identified in Step 2,

you establish a list that identifies the

most stringent control technology

option. Each other control option is then

placed after this alternative in a ranking

according to its respective emissions

performance level, ranked from lowest

emissions to highest emissions (most

effective to least stringent effective

emissions control alternative). You

should do this for each pollutant and for

each emissions unit (or grouping of

similar units) subject to a BART

analysis.

4. Step 4: For a BART Engineering

Analysis, What Impacts Must I Calculate

and Report? What Methods Does EPA

Recommend for the Impacts Analysis?

After you identify and rank the

available and technically feasible

control technology options, you must

then conduct three types of impacts

analyses when you make a BART

determination:

Impact analysis part 1: Costs of

compliance, (taking into account the

remaining useful life of the facility)

Impact analysis part 2: Energy impacts,

and

Impact analysis part 3: Non-air quality

environmental impacts.

In this section, we describe how to

conduct each of these three analyses.

You are responsible for presenting an

evaluation of each impact along with

appropriate supporting information.

You should discuss and, where

possible, quantify both beneficial and

adverse impacts. In general, the analysis

should focus on the direct impact of the

control alternative.

a. Impact analysis part 1: How do I

estimate the costs of control? To

conduct a cost analysis, you:

—Identify the emissions units being

controlled,

—Identify design parameters for

emission controls, and

—Develop cost estimates based upon

those design parameters.

It is important to identify clearly the

emission units being controlled, that is,

to specify a well-defined area or process

segment within the plant. In some cases,

multiple emission units can be

controlled jointly. However, in other

cases it may be appropriate in the cost

analysis to consider whether multiple

units will be required to install separate

and/or different control devices. The

engineering analysis should provide a

clear summary list of equipment and the

associated control costs. Inadequate

documentation of the equipment whose

emissions are being controlled is a

potential cause for confusion in

comparison of costs of the same controls

applied to similar sources.

You then specify the control system

design parameters. Potential sources of

these design parameters include

equipment vendors, background

information documents used to support

NSPS development, control technique

guidelines documents, cost manuals

developed by EPA, control data in trade

publications, and engineering and

performance test data. The following are

a few examples of design parameters for

two example control measures:

Control device Examples of design

parameters

Wet Scrubbers .......... Type of sorbent used

(lime, limestone,

etc.)

Gas pressure drop

Liquid/gas ratio.

38126 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

11The Control Cost Manual is updated

periodically. While this citation refers to the latest

version at the time this guidance was written, you

should use the version that is current as of when

you conduct your impact analysis. This document

is available at the following Web site: http://

www.epa.gov/ttn/catc/dir1/chpt2acr.pdf. 12 You should include documentation for any

additional information you used for the cost

calculations, including any information supplied by

vendors that affects your assumptions regarding

purchased equipment costs, equipment life,

replacement of major components, and any other

element of the calculation that differs from the

Control Cost Manual. 13The reason for the year 2008 is that the year

2008 is the latest year for which SIPs are due to

address the BART requirement.

14Whenever you calculate or report annual costs,

you should indicate the year for which the costs are

estimated. For example, if you use the year 2000 as

the basis for cost comparisons, you would report

that an annualized cost of $20 million would be:

$20 million (year 2000 dollars).

Control device Examples of design

parameters

Selective Catalytic

Reduction.

Ammonia to NOX

molar ratio

Pressure drop

Catalyst life.

The value selected for the design

parameter should ensure that the

control option will achieve the level of

emission control being evaluated. You

should include in your analysis,

documentation of your assumptions

regarding design parameters. Examples

of supporting references would include

the Office of Air Quality Planning and

Standards (OAQPS) Control Cost

Manual (see below) and background

information documents used for NSPS

and hazardous pollutant emission

standards. If the design parameters you

specified differ from typical designs,

you should document the difference by

supplying performance test data for the

control technology in question applied

to the same source or a similar source.

Once the control technology

alternatives and achievable emissions

performance levels have been identified,

you then develop estimates of capital

and annual costs. The basis for

equipment cost estimates also should be

documented, either with data supplied

by an equipment vendor (i.e., budget

estimates or bids) or by a referenced

source (such as the OAQPS Control Cost

Manual, Fifth Edition, February 1996,

EPA 453/B–96–001).11 In order to

maintain and improve consistency, we

recommend that you estimate control

equipment costs based on the EPA/

OAQPS Control Cost Manual, where

possible.12 The Control Cost Manual

addresses most control technologies in

sufficient detail for a BART analysis.

While the types of site-specific analyses

contained in the Control Cost Manual

are less precise than those based upon

a detailed engineering design, normally

the estimates provide results that are

plus or minus 30 percent, which is

generally sufficient for the BART

review. The cost analysis should take

into account site-specific conditions

that are out of the ordinary (e.g., use of

a more expensive fuel or additional

waste disposal costs) that may affect the

cost of a particular BART technology

option. b. How do I take into account a

project’s ‘‘remaining useful life’’ in

calculating control costs? You treat the

requirement to consider the source’s

‘‘remaining useful life’’ of the source for

BART determinations as one element of

the overall cost analysis. The

‘‘remaining useful life’’ of a source, if it

represents a relatively short time period,

may affect the annualized costs of

retrofit controls. For example, the

methods for calculating annualized

costs in EPA’s Control Cost Manual

require the use of a specified time

period for amortization that varies based

upon the type of control. If the

remaining useful life will clearly exceed

this time period, the remaining useful

life has essentially no effect on control

costs and on the BART determination

process. Where the remaining useful life

is less than the time period for

amortizing costs, you should use this

shorter time period in your cost

calculations.

For purposes of these guidelines, the

remaining useful life is the difference

between:

(1) January 1 of the year you are

conducting the BART analysis (but not

later than January 1, 2008); 13 and

(2) The date the facility stops

operations. This date must be assured

by a federally-enforceable restriction

preventing further operation. A

projected closure date, without such a

federally-enforceable restriction, is not

sufficient. (The EPA recognizes that

there may be situations where a source

operator intends to shut down a source

by a given date, but wishes to retain the

flexibility to continue operating beyond

that date in the event, for example, that

market conditions change.) We request

comment on how such flexibility could

be provided in this regard while

maintaining consistency with the

statutory requirement to install BART

within 5 years. For example, one option

that we request comment on is allowing

a source to choose between:

(1) Accepting a federally enforceable

condition requiring the source to shut

down by a given date, or

(2) Installing the level of controls that

would have been considered BART if

the BART analysis had not assumed a

reduced remaining useful life if the

source is in operation 5 years after the

date EPA approves the relevant SIP. The

source would not be allowed to operate

after the 5-year mark without such

controls.

c. What do we mean by cost

effectiveness? Cost effectiveness, in

general, is a criterion used to assess the

potential for achieving an objective at

least cost. For purposes of air pollutant

analysis, ‘‘effectiveness’’ is measured in

terms of tons of pollutant emissions

removed, and ‘‘cost’’ is measured in

terms of annualized control costs. We

recommend two types of costeffectiveness calculations—average cost

effectiveness, and incremental costeffectiveness.

In the cost analysis, you should take

care to not focus on incomplete results

or partial calculations. For example,

large capital costs for a control option

alone would not preclude selection of a

control measure if large emissions

reductions are projected. In such a case,

low or reasonable cost effectiveness

numbers may validate the option as an

appropriate BART alternative

irrespective of the large capital costs.

Similarly, projects with relatively low

capital costs may not be cost effective if

there are few emissions reduced.

d. How do I calculate average cost

effectiveness? Average cost effectiveness

means the total annualized costs of

control divided by annual emissions

reductions (the difference between

baseline annual emissions and the

estimate of emissions after controls),

using the following formula:

Average cost effectiveness

(dollars per ton removed)

Control option annualized cost

Baseline annual emissions Annual emissions with Control option

14

= −

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38127

15This is the approach in the current NSR

regulations. It is possible that this definition of

baseline period may change based upon a current

effort to amend the NSR regulations. We propose

that these guidelines should be amended to be

consistent with the approach taken in that separate

rulemaking.

Because you calculate costs in

(annualized) dollars per year ($/yr) and

because you calculate emissions rates in

tons per year (tons/yr), the result is an

average cost-effectiveness number in

(annualized) dollars per ton ($/ton) of

pollutant removed.

e. How do I calculate baseline

emissions? The baseline emissions rate

should represent a realistic depiction of

anticipated annual emissions for the

source. In general, for the existing

sources subject to BART, you will

estimate the anticipated annual

emissions based upon actual emissions

from a baseline period. 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, unless you demonstrate that

another period is more representative of

normal source operations.15

When you project that future

operating parameters (e.g., limited hours

of operation or capacity utilization, type

of fuel, raw materials or product mix or

type) will differ from past practice, and

if this projection has a deciding effect in

the BART determination, then you must

make these parameters or assumptions

into enforceable limitations. In the

absence of enforceable limitations, you

calculate baseline emissions based upon

continuation of past practice.

Examples: The baseline emissions

calculation for an emergency standby

generator may consider the fact that the

source owner would not operate more than

past practice of 2 weeks a year. On the other

hand, baseline emissions associated with a

base-loaded turbine should be based on its

past practice which would indicate a large

number of hours of operation. This produces

a significantly higher level of baseline

emissions than in the case of the emergency/

standby unit and results in more costeffective controls. As a consequence of the

dissimilar baseline emissions, BART for the

two cases could be very different.

f. How do I calculate incremental cost

effectiveness? In addition to the average

cost effectiveness of a control option,

you should also calculate incremental

cost effectiveness. You should consider

the incremental cost effectiveness in

combination with the total cost

effectiveness in order to justify

elimination of a control option. The

incremental cost effectiveness

calculation compares the costs and

emissions performance level of a control

option to those of the next most

stringent option, as shown in the

following formula:

Incremental Cost Effectiveness (dollars

per incremental ton removed) =

(Total annualized costs of control

option) ¥ (Total annualized costs

of next control option) ÷

(Next control option annual emissions)

¥ (Control option annual

emissions)

Example 1: Assume that Option F on

Figure 2 has total annualized costs of $1

million to reduce 2000 tons of a pollutant,

and that Option D on Figure 2 has total

annualized costs of $500,000 to reduce 1000

tons of the same pollutant. The incremental

cost effectiveness of Option F relative to

Option D is ($1 million ¥ $500,000) divided

by (2000 tons ¥ 1000 tons), or $500,000

divided by 1000 tons, which is $500/ton.

Example 2: Assume that two control

options exist: Option 1 and Option 2. Option

1 achieves a 100,000 ton/yr reduction at an

annual cost of $19 million. Option 2 achieves

a 98,000 tons/yr reduction at an annual cost

of $15 million. The incremental cost

effectiveness of Option 1 relative to Option

2 is ($19 million ¥ $15 million) divided by

(100,000 tons ¥ 98,000 tons). The adoption

of Option 1 instead of Option 2 results in an

incremental emission reduction of 2,000 tons

per year at an additional cost of $4,000,000

per year. The incremental cost of Option 1,

then, is $2000 per ton ¥ 10 times the average

cost of $190 per ton. While $2000 per ton

may still be deemed reasonable, it is useful

to consider both the average and incremental

cost in making an overall cost-effectiveness

finding. Of course, there may be other

differences between these options, such as,

energy or water use, or non-air

environmental effects, which also deserve

consideration in selecting a BART

technology.

You should exercise care in deriving

incremental costs of candidate control

options. Incremental cost-effectiveness

comparisons should focus on

annualized cost and emission reduction

differences between ‘‘dominant’’

alternatives. To identify dominant

alternatives, you generate a graphical

plot of total annualized costs for total

emissions reductions for all control

alternatives identified in the BART

analysis, and by identifying a ‘‘least-cost

envelope’’ as shown in Figure 2.

Example: Eight technically feasible control

options for analysis are listed in the BART

ranking. These are represented as A through

H in Figure 2. The dominant set of control

options, B, D, F, G, and H, represent the leastcost envelope, as we depict by the cost curve

connecting them. Points A, C and E are

inferior options, and you should not use

them in calculating incremental cost

effectiveness. Points A, C and E represent

inferior controls because B will buy more

emissions reductions for less money than A;

and similarly, D and F will buy more

reductions for less money than C and E,

respectively.

In calculating incremental costs, you:

(1) Rank the control options in

ascending order of annualized total

costs,

(2) Develop a graph of the most

reasonable smooth curve of the control

options, as shown in Figure 2, and

(3) Calculate the incremental cost

effectiveness for each dominant option,

which is the difference in total annual

costs between that option and the next

most stringent option, divided by the

difference in emissions reductions

between those two options. For

example, using Figure 2, you would

calculate incremental cost effectiveness

for the difference between options B and

D, options D and F, options F and G,

and options G and H.

38128 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

A comparison of incremental costs

can also be useful in evaluating the

viability of a specific control option

over a range of efficiencies. For

example, depending on the capital and

operational cost of a control device,

total and incremental cost may vary

significantly (either increasing or

decreasing) over the operational range of

a control device.

In addition, when you evaluate the

average or incremental cost

effectiveness of a control alternative,

you should make reasonable and

supportable assumptions regarding

control efficiencies. An unrealistically

low assessment of the emission

reduction potential of a certain

technology could result in inflated costeffectiveness figures.

g. What other information should I

provide in the cost impacts analysis?

You should provide documentation of

any unusual circumstances that exist for

the source that would lead to costeffectiveness estimates that would

exceed that for recent retrofits. This is

especially important in cases where

recent retrofits have cost-effectiveness

values that are within a reasonable

range, but your analysis concludes that

costs for the source being analyzed are

not reasonable.

Example: In an arid region, large amounts

of water are needed for a scrubbing system.

Acquiring water from a distant location could

greatly increase the cost effectiveness of wet

scrubbing as a control option.

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38129

h. Impact analysis part 2: How should

I analyze and report energy impacts?

You should examine the energy

requirements of the control technology

and determine whether the use of that

technology results in any significant or

unusual energy penalties or benefits. A

source owner may, for example, benefit

from the combustion of a concentrated

gas stream rich in volatile organic

compounds; on the other hand, more

often extra fuel or electricity is required

to power a control device or incinerate

a dilute gas stream. If such benefits or

penalties exist, they should be

quantified and included in the cost

analysis. Because energy penalties or

benefits can usually be quantified in

terms of additional cost or income to the

source, the energy impacts analysis can,

in most cases, simply be factored into

the cost impacts analysis. However,

certain types of control technologies

have inherent energy penalties

associated with their use. While you

should quantify these penalties, so long

as they are within the normal range for

the technology in question, you should

not, in general, consider such penalties

to be an adequate justification for

eliminating that technology from

consideration.

Your energy impact analysis should

consider only direct energy

consumption and not indirect energy

impacts. For example, you could

estimate the direct energy impacts of the

control alternative in units of energy

consumption at the source (e.g., BTU,

kWh, barrels of oil, tons of coal). The

energy requirements of the control

options should be shown in terms of

total (and in certain cases, also

incremental) energy costs per ton of

pollutant removed. You can then

convert these units into dollar costs and,

where appropriate, factor these costs

into the control cost analysis.

You generally do not consider

indirect energy impacts (such as energy

to produce raw materials for

construction of control equipment).

However, if you determine, either

independently or based on a showing by

the source owner, that the indirect

energy impact is unusual or significant

and that the impact can be well

quantified, you may consider the

indirect impact.

The energy impact analysis may also

address concerns over the use of locally

scarce fuels. The designation of a scarce

fuel may vary from region to region.

However, in general, a scarce fuel is one

which is in short supply locally and can

be better used for alternative purposes,

or one which may not be reasonably

available to the source either at the

present time or in the near future.

Finally, the energy impacts analysis

may consider whether there are relative

differences between alternatives

regarding the use of locally or regionally

available coal, and whether a given

alternative would result in significant

economic disruption or unemployment.

For example, where two options are

equally cost effective and achieve

equivalent or similar emissions

reductions, one option may be preferred

if the other alternative results in

significant disruption or

unemployment.

i. Impact analysis part 3: How do I

analyze ‘‘non-air quality environmental

impacts?’’ In the non-air quality related

environmental impacts portion of the

BART analysis, you address

environmental impacts other than air

quality due to emissions of the pollutant

in question. Such environmental

impacts include solid or hazardous

waste generation and discharges of

polluted water from a control device.

You should identify any significant or

unusual environmental impacts

associated with a control alternative that

have the potential to affect the selection

or elimination of a control alternative.

Some control technologies may have

potentially significant secondary

environmental impacts. Scrubber

effluent, for example, may affect water

quality and land use. Alternatively,

water availability may affect the

feasibility and costs of wet scrubbers.

Other examples of secondary

environmental impacts could include

hazardous waste discharges, such as

spent catalysts or contaminated carbon.

Generally, these types of environmental

concerns become important when

sensitive site-specific receptors exist or

when the incremental emissions

reductions potential of the most

stringent control is only marginally

greater than the next most-effective

option. However, the fact that a control

device creates liquid and solid waste

that must be disposed of does not

necessarily argue against selection of

that technology as BART, particularly if

the control device has been applied to

similar facilities elsewhere and the solid

or liquid waste problem under review is

similar to those other applications. On

the other hand, where you or the source

owner can show that unusual

circumstances at the proposed facility

create greater problems than

experienced elsewhere, this may

provide a basis for the elimination of

that control alternative as BART.

The procedure for conducting an

analysis of non-air quality

environmental impacts should be made

based on a consideration of site-specific

circumstances. It is not necessary to

perform this analysis of environmental

impacts for the entire list of

technologies you ranked in Step 3, if

you propose to adopt the most stringent

alternative. In that case, the analysis

need only address those control

alternatives with any significant or

unusual environmental impacts that

have the potential to affect the selection

or elimination of a control alternative.

Thus, any important relative

environmental impacts (both positive

and negative) of alternatives can be

compared with each other.

In general, the analysis of impacts

starts with the identification and

quantification of the solid, liquid, and

gaseous discharges from the control

device or devices under review.

Initially, you should perform a

qualitative or semi-quantitative

screening to narrow the analysis to

discharges with potential for causing

adverse environmental effects. Next,

you should assess the mass and

composition of any such discharges and

quantify them to the extent possible,

based on readily-available information.

You should also assemble pertinent

information about the public or

environmental consequences of

releasing these materials.

j. What are examples of non-air

quality environmental impacts? The

following are examples of how to

conduct non-air quality environmental

impacts:

• Water Impact

You should identify the relative

quantities of water used and water

pollutants produced and discharged as

a result of the use of each alternative

emission control system relative to the

most stringent alternative. Where

possible, you should assess the effect on

ground water and such local surface

water quality parameters as ph,

turbidity, dissolved oxygen, salinity,

toxic chemical levels, temperature, and

any other important considerations. The

analysis should consider whether

applicable water quality standards will

be met and the availability and

effectiveness of various techniques to

reduce potential adverse effects.

• Solid Waste Disposal Impact

You should compare the quality and

quantity of solid waste (e.g., sludges,

solids) that must be stored and disposed

of or recycled as a result of the

application of each alternative emission

control system with the quality and

quantity of wastes created with the most

stringent emission control system. You

should consider the composition and

various other characteristics of the solid

waste (such as permeability, water

retention, rewatering of dried material,

38130 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

16 Documentation of the presumption that 90–95

percent control is achievable is contained in a

recent report entitled Controlling SO2 Emissions: A

Review of Technologies, EPA–600/R–00–093,

available on the internet at http://www.epa.gov/

ORD/WebPubs/so2. This report summarizes

percentage controls for flue gas desulfurization

(FGD) systems worldwide, provides detailed

methods for evaluating costs, and explains the

reasons why costs have been decreasing with time.

17The EPA has used the cost models in the

Controlling SO2 Emissions report to calculate costeffectiveness ($/ton) estimates for FGD technologies

for a number of example cases. (See note to docket

A–2000–28 from Tim Smith, EPA/OAQPS,

December 29, 2000).

compression strength, leachability of

dissolved ions, bulk density, ability to

support vegetation growth and

hazardous characteristics) which are

significant with regard to potential

surface water pollution or transport into

and contamination of subsurface waters

or aquifers.

• Irreversible or Irretrievable

Commitment of Resources

You may consider the extent to which

the alternative emission control systems

may involve a trade-off between shortterm environmental gains at the expense

of long-term environmental losses and

the extent to which the alternative

systems may result in irreversible or

irretrievable commitment of resources

(for example, use of scarce water

resources).

• Other Adverse Environmental Impacts

You may consider significant

differences in noise levels, radiant heat,

or dissipated static electrical energy.

Other examples of non-air quality

environmental impacts would include

hazardous waste discharges such as

spent catalysts or contaminated carbon.

Generally, these types of environmental

concerns become important when the

plant is located in an area that is

sensitive to environmental degradation

and when the incremental emissions

reductions potential of the most

stringent control option is only

marginally greater than the next mosteffective option.

• Benefits to the Environment

It is important to consider relative

differences between options regarding

their beneficial impacts to non-air

quality-related environmental media.

For example, you may consider whether

a given control option results in less

deposition of pollutants to nearby

sensitive water bodies.

5. Step 5: How Do I Select the ‘‘Best’’

Alternative, Using the Results of Steps

1 Through 4?

a. Summary of the Impacts Analysis.

From the alternatives you ranked in

Step 3, you should develop a chart (or

charts) displaying for each of the ranked

alternatives:

• Expected emission rate (tons per

year, pounds per hour);

• Emissions performance level (e.g.,

percent pollutant removed, emissions

per unit product, lb/MMbtu, ppm);

• Expected emissions reductions

(tons per year);

• Costs of compliance—total

annualized costs ($), cost effectiveness

($/ton), and incremental cost

effectiveness ($/ton);

• Energy impacts (indicate any

significant energy benefits or

disadvantages);

• Non-air quality environmental

impacts (includes any significant or

unusual other media impacts, e.g., water

or solid waste), both positive and

negative.

b. Selecting a ‘‘best’’ alternative. As

discussed above, we are seeking

comment on two alternative approaches

for evaluating control options for BART.

The first involves a sequential process

for conducting the impacts analysis that

begins with a complete evaluation of the

most stringent control option. Under

this approach, you determine that the

most stringent alternative in the ranking

does not impose unreasonable costs of

compliance, taking into account both

average and incremental costs, then the

analysis begins with a presumption that

this level is selected. You then proceed

to considering whether energy and nonair quality environmental impacts

would justify selection of an alternative

control option. If there are no

outstanding issues regarding energy and

non-air quality environmental impacts,

the analysis is ended and the most

stringent alternative is identified as the

‘‘best system of continuous emission

reduction.’’

If you determine that the most

stringent alternative is unacceptable due

to such impacts, you need to document

the rationale for this finding for the

public record. Then, the next mosteffective alternative in the listing

becomes the new control candidate and

is similarly evaluated. This process

continues until you identify a

technology which does not pose

unacceptable costs of compliance,

energy and/or non-air quality

environmental impacts.

The EPA also requests comment on an

alternative decision-making approach

that would not begin with an evaluation

of the most stringent control option. For

example, you could choose to begin the

BART determination process by

evaluating the least stringent,

technically feasible control option or by

evaluating an intermediate control

option drawn from the range of

technically feasible control alternatives.

Under this approach, you would then

consider the additional emissions

reductions, costs, and other effects (if

any) of successively more stringent

control options. Under such an

approach, you would still be required to

(1) display and rank all of the options

in order of control effectiveness and to

identify the average and incremental

costs of each option; (2) consider the

energy and non-air quality

environmental impacts of each option;

and (3) provide a justification for

adopting the technology that you select

as the ‘‘best’’ level of control, including

an explanation as to why you rejected

other more stringent control

technologies.

Because of EPA’s experience in

evaluating SO2 control options for

utility boilers, the Agency is proposing

to establish a presumption regarding the

level of SO2 control that is generally

achievable for such sources. Based on

the cost models in the Controlling SO2

Emissions report,16 it appears that,

where there is no existing control

technology in place, 90–95 percent

control can generally be achieved at

cost-effectiveness values that are in the

hundreds of dollars per ton range or

less.17 We are thus proposing a

presumption that, for uncontrolled

utility boilers, an SO2-control level in

the 90–95 range is generally achievable.

If you wish to demonstrate a BART level

of control that is less than any

presumption established the final

guidelines, you would need to

demonstrate the source-specific

circumstances with respect to costs,

remaining useful life, non-air quality

environmental impacts, or energy

impacts that would justify less stringent

controls than for a typical utility boiler.

We believe that the ‘‘consideration of

cost’’ factor for source-by-source BART,

which is a technology-based approach,

generally requires selection of control

measures that are within this level of

cost effectiveness. We recognize,

however, that the population of utility

boilers subject to BART may have caseby-case variations (for example, type of

fuel used, severe space limitations, and

presence of existing control equipment)

that could affect the costs of applying

retrofit controls. We invite comments on

whether the 90–95 percent presumption

is appropriate, or whether another

presumption should be established

instead. If commenters want to offer a

different presumption they should

provide documentation supporting the

basis for their proposal.

For evaluating the significance of the

costs of compliance, EPA requests

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38131

18Technical Support Documentation. Voluntary

Emissions Reduction Program for Major Industrial

Sources of Sulfur Dioxide in Nine Western States

and a Backstop Market Trading Program. An Annex

to the Report of the Grand Canyon Visibility

Transport Commission. Section 6A.

19 (The current draft of this document is entitled

Guidance for Attainment of Air Quality Goals for

PM2.5 and Regional Haze. We expect this document

will be released in final form before the publication

of the final rule for the BART guidelines.)

comment on whether the final rule

should contain specific criteria, and on

whether such criteria would improve

implementation of the BART

requirement. For example, in the work

of the Western Regional Air Partnership

(WRAP),18 a system is described which

views as ‘‘low cost’’ those controls with

an average cost effectiveness below

$500/ton, as ‘‘moderate’’ those controls

with an average cost effectiveness

between $500 to 3000 per ton, and as

‘‘high’’ those controls with an average

cost effectiveness greater than $3000 per

ton.

c. In selecting a ‘‘best’’ alternative,

should I consider the affordability of

controls? Even if the control technology

is cost effective, there may be cases

where the installation of controls would

affect the viability of continued plant

operations.

As a general matter, for plants that are

essentially uncontrolled at present, and

emit at much greater levels per unit of

production than other plants in the

category, we are unlikely to accept as

BART any analysis that preserves a

source’s uncontrolled status. While this

result may predict the shutdown of

some facilities, we believe that the

flexibility provided in the regional haze

rule for an alternative reduction

approach, such as an emissions trading

program, will minimize the likelihood

of shutdowns.

Nonetheless, we recognize there may

be unusual circumstances that justify

taking into consideration the conditions

of the plant and the economic effects of

requiring the use of a given control

technology. These effects would include

effects on product prices, the market

share, and profitability of the source.

We do not intend, for example, that the

most stringent alternative must always

be selected, if that level would cause a

plant to shut down, while a slightly

lesser degree of control would not have

this effect. Where there are such

unusual circumstances that are judged

to have a severe effect on 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 a severe impact on plant

operations you may consider them in

the selection process, so long as you

provide an economic analysis that

demonstrates, in sufficient detail for a

meaningful 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 should

consider whether other competing

plants in the same industry may also be

required to install BART controls.

V. Cumulative Air Quality Analysis

A. What Air Quality Analysis Do We

Require in the Regional Haze Rule for

Purposes of BART Determinations?

In the regional haze rule, we require

the following in 40 CFR

51.308(e)(1)(ii)(B):

An analysis of the degree of visibility

improvement that would be achieved in each

mandatory Class I Federal area as a result of

the emission reductions from all sources

subject to BART located within the region

that contributes to visibility impairment in

the Class I area, based on the * * * [results

of the engineering analysis required by 40

CFR 51.308(e)(1)(ii)(A)] * * *

This means that the regional haze rule

requires you to conduct a regional

modeling analysis which addresses the

total cumulative regional visibility

improvement if all sources subject to

BART were to install the ‘‘best’’ controls

selected according to the engineering

analysis described above in section IV of

these guidelines. We are developing

guidelines for regional air quality

modeling.19

B. How Do I Consider the Results of This

Analysis in My Selection of BART for

Individual Sources?

You use a regional modeling analysis

to assess the cumulative impact on

visibility of the controls selected in the

engineering analysis for the time period

for the first regional haze SIP, that is,

the time period between the baseline

period and the year 2018. You use this

cumulative impact assessment to make

a determination of whether the controls

you identified, in their entirety, provide

a sufficient visibility improvement to

justify their installation. We believe that

there is a sufficient basis for the controls

if you can demonstrate for any Class I

area that any of the following criteria are

met:

(1) The cumulative visibility

improvement is a substantial fraction of

the achievable visibility improvement

from all measures included in the SIP,

or is a substantial fraction of the

visibility goal selected for any Class I

area (EPA believes that for such

situations, the controls would be

essential to ensure progress towards a

long-term improvement in visibility);

OR

(2) The cumulative visibility

improvement is necessary to prevent

any degradation from current conditions

on the best visibility days.

Note that under 40 CFR

51.308(e)(1)(ii)(B), the passage cited

above, the rule does not provide for

modeling of subgroupings of the BART

population within a region, nor for

determinations that some, but not all, of

the controls selected in the engineering

analysis may be included in the SIP.

Thus, to comply with 40 CFR

51.308(e)(1), the visibility SIP must

provide for BART emission limitations

for all sources subject to BART (or

demonstrate that BART-level controls

are already in place and required by the

SIP), unless you provide a

demonstration that no BART controls

are justifiable based upon the

cumulative visibility analysis.

VI. Enforceable Limits/Compliance Date

To complete the BART process, you

must establish enforceable emission

limits and require compliance within a

given period of time. In particular, you

must establish an enforceable emission

limit for each subject emission unit at

the source and for each pollutant subject

to review that is emitted from the

source. In addition, you must require

compliance with the BART emission

limitations no later than 5 years after

EPA approves your SIP. If technological

or economic limitations in the

application of a measurement

methodology to a particular emission

unit would make an emissions limit

infeasible, you may prescribe a design,

equipment, work practice, operation

standard, or combination of these types

of standards. You should ensure that

any BART requirements are written in a

way that clearly specifies the individual

emission unit(s) subject to BART

review. Because the BART requirements

are ‘‘applicable’’ requirements of the

CAA, they must be included as title V

permit conditions according to the

procedures established in 40 CFR part

70 or 40 CFR part 71.

Section 302(k) of the CAA requires

emissions limits such as BART to be

met on a continuous basis. Although

this provision does not necessarily

require the use of continuous emissions

monitoring (CEMs), it is important that

sources employ techniques that ensure

compliance on a continuous basis.

Monitoring requirements generally

applicable to sources, including those

that are subject to BART, are governed

by other regulations. See, e.g., 40 CFR

38132 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

20We focus in this section on emission cap and

trade programs which we believe will be the most

common type of economic incentive program

developed as an alternative to BART.

21An emission budget generally represents a total

emission amount for a single pollutant such as SO2.

As noted in the preamble to the regional haze rule

(64 FR 35743, July 1, 1999) we believe that

unresolved technical difficulties preclude interpollutant trading at this time.

part 64 (compliance assurance

monitoring); 40 CFR 70.6(a)(3) (periodic

monitoring); 40 CFR 70.6(c)(1)

(sufficiency monitoring). Note also that

while we do not believe that CEMs

would necessarily be required for all

BART sources, the vast majority of

electric generating units already employ

CEM technology for other programs,

such as the acid rain program. In

addition, emissions limits must be

enforceable as a practical matter

(contain appropriate averaging times,

compliance verification procedures and

recordkeeping requirements). In light of

the above, the permit must:

• Be sufficient to show compliance or

noncompliance (i.e., through monitoring

times of operation, fuel input, or other

indices of operating conditions and

practices); and

• Specify a reasonable averaging time

consistent with established reference

methods, contain reference methods for

determining compliance, and provide

for adequate reporting and

recordkeeping so that air quality agency

personnel can determine the

compliance status of the source.

VII. Emission Trading Program

Overview

40 CFR 51.308(e)(2) allows States the

option of implementing an emissions

trading program or other alternative

measure instead of requiring BART.

This option provides the opportunity for

achieving better environmental results

at a lower cost than under a source-bysource BART requirement. A trading

program must include participation by

BART sources, but may also include

sources that are not subject to BART.

The program would allow for

implementation during the first

implementation period of the regional

haze rule (that is, by the year 2018)

instead of the 5-year compliance period

noted above. In this section of the

guidance, we provide an overview of the

steps in developing a trading program 20

consistent with 40 CFR 51.308(e)(2).

A. What Are the General Steps in

Developing an Emission Trading

Program?

The basic steps are to:

(1) Develop emission budgets;

(2) Allocate emission allowances to

individual sources; and

(3) Develop a system for tracking

individual source emissions and

allowances. (For example, procedures

for transactions, monitoring, compliance

and other means of ensuring program

accountability).

B. What Are Emission Budgets and

Allowances?

An emissions budget is a limit, for a

given source population, on the total

emissions amount 21 that may be

emitted by those sources over a State or

region. An emission budget is also

referred to as an ‘‘emission cap.’’

In general, the emission budget is

subdivided into source-specific amounts

that we refer to as ‘‘allowances.’’

Generally, each allowance equals one

ton of emissions. Sources must hold

allowances for all emissions of the

pollutant covered by the program that

they emit. Once you allocate the

allowances, source owners have

flexibility in determining how they will

meet their emissions limit. Source

owners have the options of:

—Emitting at the level of allowances

they are allocated (for example, by

controlling emissions or curtailing

operations),

—Emitting at amounts less than the

allowance level, thus freeing up

allowances that may be used by other

sources owned by the same owner, or

sold to another source owner, or

—Emitting at amounts greater than the

allowance level, and purchasing

allowances from other sources or

using excess allowances from another

plant under the same ownership.

A good example of an emissions

trading program is the acid rain program

under title IV of the CAA. The acid rain

program is a national program—it

establishes a national emissions cap,

allocates allowances to individual

sources, and allows trading of

allowances between all covered sources

in the United States. The Ozone

Transport Commission’s NOX

Memorandum of Understanding, and

the NOX SIP call both provide for

regional trading programs. Other trading

programs generally have applied only to

sources within a single State. A regional

multi-State program provides greater

opportunities for emission trading, and

should be considered by regional

planning organizations that are

evaluating alternatives to sourcespecific BART. The WRAP has

recommended a regional market trading

program as a backstop to its overall

emission reduction program for SO2.

Although regional trading programs

require more interstate coordination,

EPA has expertise that it can offer to

States wishing to pursue such a

program.

C. What Criteria Must Be Met in

Developing an Emission Trading

Program as an Alternative to BART?

Under the regional haze rule, an

emission trading program must achieve

‘‘greater reasonable progress’’ (that is,

greater visibility improvement) than

would be achieved through the

installation and operation of sourcespecific BART. The ‘‘greater reasonable

progress’’ demonstration involves the

following steps, which are discussed in

more detail below:

—Identify the sources that are subject to

BART,

—Calculate the emissions reductions

that would be achieved if BART were

installed and operated on sources

subject to BART,

—Demonstrate whether your emission

budget achieves emission levels that

are equivalent to or less than the

emissions levels that would result if

BART were installed and operated,

—Analyze whether implementing a

trading program in lieu of BART

would likely lead to differences in the

geographic distribution of emissions

within a region, and

—Demonstrate that the emission levels

will achieve greater progress in

visibility than would be achieved if

BART were installed and operated on

sources subject to BART.

1. How Do I Identify Sources Subject to

BART?

For a trading program, you would

identify sources subject to BART in the

same way as we described in sections II

and III of these guidelines.

2. How Do I Calculate the Emissions

Reductions That Would Be Achieved If

BART Were Installed and Operated on

These Sources?

For a trading program under

51.308(e)(2), you may identify these

emission reductions by:

—Conducting a case-by-case analysis for

each of the sources, using the

procedures described above in these

guidelines in sections II through V;

—Conducting an analysis for each

source category that takes into

account the available technologies,

the costs of compliance, the energy

impacts, the non-air quality

environmental impacts, the pollution

control equipment in use, and the

remaining useful life, on a categorywide basis; or

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38133

22We request comment on whether these

guidelines should recommend a weighted average

of the values instead of presenting the values as a

range.

23As required by 40 CFR 51.308(e)(2)(iii),

emissions reductions must take place during the

period of the first long-term strategy for regional

haze. This means the reductions must take place no

later than the year 2018.

24The base year must reflect the year of the most

current available emission inventory, in many cases

the year 2002, and this base year should not be later

than the 2000–2004 time period used for baseline

purposes under the regional haze rule.

—Conducting an analysis that combines

considerations on both source-specific

and category-wide information.

For a category-wide analysis of

available control options, you develop

cost estimates and estimates of energy

and non-air quality environmental

impacts that you judge representative of

the sources subject to BART for a source

category as a whole, rather than analyze

each source that is subject to BART. The

basic steps of a category-wide analysis

are the same as for a source-specific

analysis. You identify technically

feasible control options and rank them

according to control stringency. Next,

you calculate the costs and cost

effectiveness for each control option,

beginning with the most stringent

option. Likely, the category-wide

estimate will represent a range of cost

and cost-effectiveness values rather than

a single number.22 Next, you evaluate

the expected energy and non-air quality

impacts (both positive and negative

impacts) to determine whether these

impacts preclude selection of a given

alternative.

The EPA requests comment on an

approach to the category-wide analysis

of BART that would allow the States to

evaluate different levels of BART

control options (e.g., all measures less

than $1000/ton vs. all measures less

than $2000/ton vs. all measures less

than $3000/ton) through an iterative

process of assessing relative changes in

cumulative visibility impairment. For

example, States or regional planning

organizations could use $1000 or $2000/

ton as an initial cutoff for selecting

reasonable control options. The States

or regional planning organizations could

then compare the across-the-board

regional emissions and visibility

changes resulting from the

implementation of the initial control

option and that resulting from the

implementation of control options with

a $3000/ton cutoff (or $1500/ton, etc).

This approach would allow States and

other stakeholders to understand the

visibility differences among BART

control options achieving less costeffective or more cost-effective levels of

overall control.

3. For a Cap and Trade Program, How

Do I Demonstrate That My Emission

Budget Results in Emission Levels That

Are Equivalent To or Less Than the

Emissions Levels That Would Result If

BART Were Installed and Operated?

Emissions budgets must address two

criteria. First, you must develop an

emissions budget for a future year 23

which ensures reductions in actual

emissions that achieve greater

reasonable visibility progress than

BART. This will generally necessitate

development of a ‘‘baseline forecast’’ of

emissions for the population of sources

included within the budget. A baseline

forecast is a prediction of the future

emissions for that source population in

absence of either BART or the

alternative trading program. Second,

you must take into consideration the

timing of the emission budget relative to

the timetable for BART. If the

implementation timetable for the

emission trading program is a

significantly longer period than the 5-

year time period for BART

implementation, you should establish

budgets for interim years that ensure

steady and continuing progress in

emissions reductions.

In evaluating whether the program

milestone for the year 2018 provides for

a BART-equivalent or better emission

inventory total, you conduct the

following steps:

—Identify the source population

included within the budget, which

must include all BART sources and

may include other sources,

—For sources included within the

budget, develop a base year 24

emissions inventory for stationary

sources included within the budget,

using the most current available

emission inventory,

—Develop a future emissions inventory

for the milestone year (in most cases,

the year 2018), that is, an inventory of

projected emissions for the milestone

year in the absence of BART or a

trading program,

—Calculate the reductions from the

forecasted emissions if BART were

installed on all sources subject to

BART,

—Subtract this amount from the

forecasted total, and

—Compare the budget you have selected

and confirm that it does not exceed

this level of emissions.

Example: For a given region for which a

budget is being developed for SO2, the most

recent inventory is for the year 2002. The

budget you propose for the trading program

is 1.2 million tons. The projected emissions

inventory total for the year 2018, using the

year 2002 inventory and growth projections,

is 4 million tons per year. Application of

BART controls on the population of sources

subject to BART would achieve 2.5 million

tons per year of reductions. Subtracting this

amount from the project inventory yields a

value of 1.5 million tons. Because your

selected budget of 1.2 million tons is less

than this value, it achieves a better than a

BART-equivalent emission total.

4. How Do I Ensure That Trading

Budgets Achieve ‘‘Greater Reasonable

Progress?’’

In some cases, you may be able to

demonstrate that a trading program that

achieves greater emissions progress may

also achieve greater visibility progress

without necessarily conducting a

detailed dispersion modeling analysis.

This could be done, for example, if you

can demonstrate, using economic

models, that the likely distribution of

emissions when the trading program is

implemented would not be significantly

different than the distribution of

emissions if BART was in place. If

distribution of emissions is not

substantially different than under

BART, and greater emissions reductions

are achieved, then the trading program

would presumptively achieve ‘‘greater

reasonable progress.’’

If the distribution of emissions is

different under the two approaches,

then the possibility exists that the

trading program, even though it

achieves greater emissions reductions,

may not achieve better visibility

improvement. Where this is the case,

then you must conduct dispersion

modeling to determine the visibility

impact of the trading alternative. The

dispersion modeling should determine

differences in visibility between BART

and the trading program for each

impacted Class I area, for the worst and

best 20 percent of days. The modeling

should identify:

—The estimated difference in visibility

conditions under the two approaches

for each Class I area,

—The average difference in visibility

over all Class I areas impacted by the

region’s emissions. [For example, if

six Class I areas are in the region

impacted, you would take the average

of the improvement in deciviews over

those six areas].

38134 Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules

The modeling study would demonstrate

‘‘greater reasonable progress’’ if both of

the following two criteria are met:

—Visibility does not decline in any

Class I area

Example: In Class I area X, BART would

result in 2.5 deciviews of improvement but

the trading program would achieve 1.4

deciviews. The criterion would be met

because the trading program results in

improvement of 1.4 deciviews, rather than a

decline in visibility.

—Overall improvement in visibility,

determined by comparing the average

differences over all affected Class I

areas

Example: For the same scenario, assume

that ten Class I areas are impacted. The

average deciview improvement from BART

for the ten Class I areas is 3.5 deciviews (the

2.5 deciview value noted above, and values

for the remaining areas of 3.9, 4.1, 1.7, 3.3,

4.5, 3.1, 3.6, 3.8 and 4.5). The average of the

ten deciview values for the trading program

must be 3.5 deciviews or more.

5. How Do I Allocate Emissions to

Sources?

Emission allocations must be

consistent with the overall budget that

you provide to us. We believe it is not

appropriate for EPA to require a

particular process and criteria for

individual source allocations, and thus

we will not dictate how to allocate

allowances. We will provide

information on allocation processes to

State and local agencies, and to regional

planning organizations.

6. What Provisions Must I Include in

Developing a System for Tracking

Individual Source Emissions and

Allowances?

The EPA requests comment generally

on what the BART guidelines should

require in terms of the level of detail for

the administration of a trading program

and for the tracking of emissions and

allowances. In general, we expect

regional haze trading programs to

contain the same degree of rigor as

trading programs for criteria pollutants.

In terms of ensuring the overall integrity

and enforceability of a trading program,

we expect that you will generally follow

the guidance already being developed

for other economic incentive programs

(EIPs) in establishing a trading program

for regional haze. In addition, we expect

that any future trading programs

developed by States and/or regional

planning organizations will be

developed in consultation with a broad

range of stakeholders.

There are two EPA-administered

emission trading programs that we

believe provide good examples of the

features of a well-run trading program.

These two programs provide

considerable information that would be

useful to the development of regional

haze trading programs as an alternative

to BART.

The first example is EPA’s acid rain

program under title IV of the CAA.

Phase I of the acid rain reduction

program began in 1995. Under phase I,

reductions in the overall SO2 emissions

were required from large coal-burning

boilers in 110 power plants in 21

midwest, Appalachian, southeastern

and northeastern States. Phase II of the

acid rain program began in 2000, and

required further reductions in the SO2

emissions from coal-burning power

plants. Phase II also extended the

program to cover other lesser-emitting

sources. Allowance trading is the

centerpiece of EPA’s acid rain program

for SO2. You will find information on

this program in:

—Title IV of the CAA Amendments

(1990),

—40 CFR part 73 at 58 FR 3687 (January

1993),

—EPA’s acid rain website, at

www.epa.gov/acidrain/trading.html.

The second example is the rule for

reducing regional transport of groundlevel ozone (NOX SIP call). The NOX SIP

call rule requires a number of eastern,

midwestern, and southeastern States

and the District of Columbia to submit

SIPs that address the regional transport

of ground-level ozone through

reductions in NOX. States may meet the

requirements of the rule by participating

in an EPA-administered trading

program. To participate in the program,

the States must submit rules sufficiently

similar to a model trading rule

promulgated by the Agency (40 CFR

part 96). More information on this

program is available in:

—The preamble and rule in the Federal

Register at 63 FR 57356 (October

1998),

—The NOX compliance guide, available

at www.epa.gov/acidrain/modlrule/

main.html#126,

—Fact sheets for the rule, available at

www.epa.gov/ttn/rto/sip/

related.html#prop,

—Additional information available on

EPA’s web site, at www.epa.gov/

acidrain/modlrule/main.html.

A third program that provides a good

example of trading programs is the the

Ozone Transport Commission (OTC)

NOX budget program. The OTC NOX

budget program was created to reduce

summertime NOX emissions in the

northeast United States. The program

caps NOX emissions for the affected

States at less than half of the 1990

baseline emission level of 490,000 tons,

and uses trading to achieve costeffective compliance. For more

information on the trading provisions of

the program, see:

—Memorandum of Understanding

(MOU), available at www.sso.org/otc/

att2.HTM,

—Fact sheets available at www.sso.org/

otc/Publications/327facts.htm,

—Additional information, available at

www.epa.gov/acidrain/otc/

otcmain.html.

The EPA is including in the docket for

this rulemaking a detailed presentation

that has been used by EPA’s Clean Air

Markets Division to explain the

provisions of NOX trading programs

with State and local officials. This

presentation provides considerable

information on EPA’s views on sound

trading programs.

The EPA recognizes that it is desirable

to minimize administrative burdens for

sources that may be subject to the

provisions of several different emission

trading programs. We believe that it is

desirable for any emission trading

program for BART to use existing

tracking systems to the extent possible.

At the same time, we request comment

on whether States and/or regional

planning organizations should conduct

additional technical analyses (and, if so,

to what extent) to determine whether

the time periods for tracking of

allowances under existing programs

(i.e., annual allowances for SO2 for the

acid rain program, and allowances for

the ozone season for NOX) are

appropriate for purposes of

demonstrating greater reasonable

regional progress vis a vis BART. The

EPA expects that if such analyses are

conducted, they would be conducted in

conjunction with the timelines for

development of SIPs for regional haze.

7. How Would a Regional Haze Trading

Program Interface With the

Requirements for ‘‘Reasonably

Attributable’’ BART Under 40 CFR

51.302 of the Regional Haze Rule?

If a State elects to impose case-by-case

BART emission limitations according to

40 CFR 51.308(e)(1) of the regional haze

rule, then there should be no difficulties

arising from the implementation of

requirement for ‘‘reasonably

attributable’’ BART under 40 CFR

51.302. However, if a State chooses an

alternative measure, such as an

emissions trading program, in lieu of

requiring BART emissions limitation on

specific sources, then the requirement

for BART is not satisfied until

alternative measures reduce emissions

sufficient to make ‘‘more reasonable

progress than BART.’’ Thus, in that

Federal Register / Vol. 66, No. 140 / Friday, July 20, 2001 / Proposed Rules 38135

period between implementation of an

emissions trading program and the

satisfaction of the overall BART

requirement, an individual source could

be required to install BART for

reasonably attributable impairment

under 40 CFR 51.302. Because such an

overlay of the requirements under 40

CFR 51.302 on a trading program under

40 CFR 51.308 might affect the

economic and other considerations that

were used in developing the emissions

trading program, the regional haze rule

allows for a ‘‘geographic enhancement’’

under 40 CFR 51.308. This provision

addresses the interface between a

regional trading program and the

requirement under 40 CFR 51.302

regarding BART for reasonably

attributable visibility impairment. (See

40 CFR 51.308(e)(2)(v)).

The EPA recognizes the desirability of

addressing any such issues at the outset

of developing an emissions trading

program to address regional haze. We

note that the WRAP, the planning

organization for the nine western States

considering a trading program under 40

CFR 51.309 (which contains a similar

geographic enhancement provision), has

adopted policies which target use of the

51.302 provisions by the Federal Land

Managers (FLMs). In this case for the

nine WRAP States, the FLMs have

agreed that they will certify reasonable

attributable impairment only under

certain specific conditions. Under this

approach, the FLMs would certify under

40 CFR 51.302 only if the regional

trading program is not decreasing

sulfate concentrations in a Class I area

within the region. Moreover, the FLMs

will certify impairment under 40 CFR

51.302 only where: (1) BART-eligible

sources are located ‘‘near’’ that class I

area and (2) those sources have not

implemented BART controls. In

addition, the WRAP is investigating

other procedures for States to follow in

responding to a certification of

‘‘reasonably attributable’’ impairment if

an emissions trading approach is

adopted to address the BART

requirement based on the sources’

impact on regional haze.

The specific pollutants and the

magnitude of impacts under the regional

haze rule and at specific Class I areas

may vary in different regions of the

country. We expect that each State

through its associated regional planning

organization will evaluate the need for

geographic enhancement procedures

within any adopted regional emissions

trading program.

List of Subjects in 40 CFR Part 51

Environmental protection,

Administrative practice and procedure,

Air pollution control, Carbon monoxide,

Nitrogen dioxide, Particulate matter,

Sulfur oxides, Volatile organic

compounds.

Dated: June 22, 2001.

Christine T. Whitman,

Administrator.

In addition to the guidelines

described above, part 51 of chapter I of

title 40 of the Code of Federal

Regulations is proposed to be amended

as follows:

PART 51—REQUIREMENTS FOR

PREPARATION, ADOPTION, AND

SUBMITTAL OF IMPLEMENTATION

PLANS

1. The authority citation for part 51

continues to read as follows:

Authority: 23 U.S.C. 101; 42 U.S.C. 7410–

7671q.

2. Section 51.302 is amended by

revising paragraph (c)(4)(iii) to read as

follows:

§ 51.302 Implementation control strategies

for reasonably attributable visibility

impairment.

* * * * *

(c) * * *

(4) * * *

(iii) BART must be determined for

fossil-fuel fired generating plants having

a total generating capacity in excess of

750 megawatts pursuant to ‘‘Guidelines

for Determining Best Available Retrofit

Technology for Coal-fired Power Plants

and Other Existing Stationary Facilities’

(1980), which is incorporated by

reference, exclusive of appendix E,

which was published in the Federal

Register on February 6, 1980 (45 FR

8210), except that options more

stringent than NSPS must be

considered. Establishing a BART

emission limitation equivalent to the

NSPS level of control is not a sufficient

basis to avoid the detailed analysis of

control options required by the

guidelines. It is EPA publication No.

450/3–80–009b and is for sale from the

U.S. Department of Commerce, National

Technical Information Service, 5285

Port Royal Road, Springfield, Virginia

22161.

* * * * *

3. Section 51.308 is amended by

adding paragraph(e)(1)(ii)(C) as follows:

§ 51.308 Regional haze program

requirements.

* * * * *

(e) * * *

(1) * * *

(ii) * * *

(C) Appendix Y of this part provides

guidelines for conducting the analyses

under paragraphs (e)(1)(ii)(A) and

(e)(1)(ii)(B) of this section. All BART

determinations that are required in

paragraph (e)(1) of this section must be

made pursuant to the guidelines in

appendix Y of this part.

* * * * *

[FR Doc. 01–18094 Filed 7–19–01; 8:45 am]

BILLING CODE 6560–50–P

ATTACHMENT G 

May 24, 2002, District of Columbia Court of Appeals Decision (no. 99-

1348), American Corn Growers Association vs. EPA 
P:\23\62\833 - MPCA Tac BART\Task 2\Task 2B\ACGA vs. EPA.DOC 1 

United States Court of Appeals 

FOR THE DISTRICT OF COLUMBIA CIRCUIT 

Argued February 25, 2002 

Decided May 24, 2002 

No. 99-1348 

American Corn Growers Association, 

Petitioner 

v. 

Environmental Protection Agency, 

Respondent 

State of Michigan, Department of 

Environmental Quality, et al., 

Intervenors 

Consolidated with Nos. 99-1349, 99-1350, 

99-1351, 99-1352, 99-1357, 99-1358, 99-1359, 

01-1111, 01-1112, 01-1113 

On Petitions for Review of an Order of the 

Environmental Protection Agency 

 Peter Glaser argued the cause for Industry petitioners and intervenors on the BART Issues in Case Nos. 99-1348, 99-1349, 99-1350, 99-1351, 99-1352, 99-1356, 99-1357, 99-1358 and 99-1359. With him on the joint briefs were Paul M. Seby, Henry V. Nickel, F. William Brownell, Michael L. Teague, Kevin L. Fast, David M. Flannery, Kathy G. Beckett, Scott D. Goldman, Harold P. Quinn, Jr., William H. Lewis, Jr., and Michael A. McCord.  Kevin L. Fast argued the cause for Industry petitioners in Case Nos. 01-1111, 01-1112 and 01-1113. With him on the joint briefs were Peter Glaser, Paul M. Seby, Henry V. Nickel, F. William Brownell, and Michael L. Teague.  David S. Baron argued the cause and filed the briefs for petitioner Sierra Club. 

 Jennifer M. Granholm, Attorney General, SCasey, Solicitor General, and John Fordell Leonwere on the briefs for intervenor State of Michi Pamela S. Tonglao, Kenneth C. Amaditz, aU.S. Department of Justice, argued the causes fbrief was M. Lea Anderson, Attorney, U.S. Env Erick Titrud argued the cause for intervenoHampshire, State of Vermont, and Tribal and Ehim on the joint brief were Ann Brewster WeekGrantham, G. Steven Rowe, Attorney General, McLaughlin, Attorney General, State of New HSenior Assistant Attorney General, and William State of Vermont.  Peter Glaser, Henry V. Nickel, F. William BKevin L. Fast, Paul M. Seby, Harold P. Quinn, 

General, State of Michigan, John Fordell LeoneDavid M. Flannery, Kathy G. Beckett, William McCord were on the joint brief for Industry and respondents.  Mark L. Shurtleff, Attorney General, State Attorney General, and Susan M. McMichael weState of Utah and State of New Mexico Environrespondent EPA.  Before: Edwards, Randolph, and Garland,  Opinion for the Court filed Per Curiam.  Opinion concurring in part and dissenting i

Garland.  Per Curiam: In 1999, the Environmental Prfinal rule to address regional haze. See Region35,714 (July 1, 1999). The Haze Rule calls for designing and implementing regional haze progparks and wilderness areas that have been class
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Federal areas,"1 such as Yellowstone National Park, Grand Canyon National 

Park, and Shenandoah National Park. See 40 C.F.R. ss 81.401-.437 (listing areas that have been designated as Class I areas where visibility is an important value). Numerous petitioners now challenge the Haze Rule. We vacate the rule in part and sustain it in part. 

I. Introduction 

 "Regional haze," as EPA defines it, is visibility impairment caused by geographically dispersed sources emitting fine particles and their precursors into the air. See 64 Fed. Reg. at 35,715. The emission and movement of sulfur dioxide, oxides of nitrogen, and fine particulate matter from sources, such as power plants, contribute to haze. See id. Fine particulate matter scatters and absorbs light. See id.  Haze has degraded visibility in most of the country's national parks and wilderness areas. See id. The average visual range in many Class I areas in the western United States is 100 to 150 kilometers - which is just one-half to twothirds the estimated visual range that would exist without manmade air pollution. See id. In most of the eastern United States, the average visual range is less than 30 kilometers - or about one-fifth the visual range that would exist under estimated natural conditions. See id.  Before 1977, the Clean Air Act (the "CAA" or the "Act") "did not elaborate on the protection of visibility as an air-quality related value." Chevron U.S.A., Inc. v. EPA, 658 F.2d 271, 272 (5th Cir. 1981). But in 1977, "[i]n response to a growing awareness that visibility was rapidly deteriorating in many places, such as wilderness areas and national parks," id. at 272, Congress added s 169A to the Act. See Clean Air Act Amendments of 1977, Pub. L. No. 95-95, s 128, 91 Stat. 685, 742 (current version at 42 U.S.C. s 7491). Section 169A established as a 

1 "Class I" areas include all international parks, national wilder-ness areas which 

exceed 5,000 acres in size, national memorial parks which exceed 5,000 acres in size, and national parks which exceed 6,000 acres in size and which were in existence on August 7, 1977. See 42 U.S.C. s 7472(a). The term "mandatory class I Federal areas" is defined as "Federal areas which may not be designated as other than class I." Id. s 7491(g)(5). At the time the Haze Rule was promulgated, there were 156 Class I areas across the country. See 64 Fed. Reg. at 35,714. 

national goal the "prevention of any future, and impairment in visibility in mandatory class I arefrom man-made air pollution." See 91 Stat. at 7s 7491(a)(1)). Congress directed EPA to issue submit State Implementation Plans ("SIPs") conschedules of compliance, and other measures neprogress toward meeting the national visibility version at 42 U.S.C. s 7491(b)(2)). In addition, address possible visibility impairment caused bstationary sources which had been in operation Stat. at 743 (current version at 42 U.S.C. s 7491 Congress also gave EPA the responsibility under s 169A to "assure ... reasonable progress goal." See 91 Stat. at 742-43 (current version aissued its first regulations in 1980. See 45 Fed. 1980 visibility regulations, which apply to statearea, addressed visibility impairment reasonabla small number of sources. See id. at 80,085. Eregulations to impairment attributable to specifion regional haze attributable to multiple sourcegraphic regions because there was insufficient dbetween emitted pollutants, pollutant trans-port id. at 80,086.  In 1990, Congress amended the Clean Air Aattempt to prompt EPA to further address visibiand wilderness areas. See Clean Air Act Amen816, 104 Stat. 2695 (1990) (current version at 4requires, among other things, that EPA under-taand "source regions" of visibility impairment in designating transport commissions to study the pollutants, and establish a transport commission Park. See 42 U.S.C. s 7492.  EPA established the Grand Canyon Visibili("GCVTC") in 1991 to assess information abouin and around sixteen Class I areas on the Colorprovide policy recommendations to EPA to addReg. 57,522 (Nov. 12, 1991). The GCVTC issu
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Then in 1997 EPA issued a notice of proposed rulemaking with regard to regional haze, see 62 Fed. Reg. 41,138 (July 31, 1997), noting that advances in scientific and technical knowledge, including analyses provided by the GCVTC, had made it possible for EPA to target region-wide visibility impairment. After receiving more than 1,300 comments to the proposed rule, EPA published the final Haze Rule on July 1, 1999. See 64 Fed. Reg. at 35,714. The final Haze Rule reaches all states because, EPA concluded, all states contain sources whose emissions are "reasonably anticipated to contribute to regional haze in a Class I area." Id. at 35,721. Under the Haze Rule, a state must develop and submit a 

SIP that provides for reasonable progress toward achieving "natural visibility conditions" in the national parks and wilderness areas in that state. See 40 C.F.R. s 51.308(d)(1). SIPs addressing regional haze in an "attainment" area must be submitted within one year of the date the area is designated as "attainment," and revised SIPs for "non-attainment" areas must be submitted within three years after the designation. See id. s 51.308(b)(1)-(2).  The Haze Rule, for the most part, does not specify what control measures a state must implement in its initial SIP. See 64 Fed. Reg. at 35,721 (noting that the determination of what specific control measures must be implemented "can only be made by a State once it has conducted the necessary technical analyses of emissions, air quality, and the other factors that go into determining reasonable progress"). But the rule does require states to: (1) provide for an improvement in visibility in the 20 percent most impaired days; (2) ensure that there is no degradation in visibility during the 20 percent clearest days; and (3) determine the annual rate of visibility improvement that would lead to "natural visibility" conditions in 60 years. See 40 C.F.R. s 51.308(d)(1); see also id. s 51.301; 64 Fed. Reg. at 35,734. A state may not adopt a rate of improvement that would achieve natural visibility conditions in more than 60 years unless it demonstrates that the 60-year rate is unreasonable. See 40 C.F.R. s 51.308(d)(1)(ii).  The Haze Rule also provides that each state must develop a long-term strategy for achieving its visibility improvement goals. This strategy must include the identification of all major stationary sources subject to Best Available Retrofit Technology ("BART") requirements. See id. s 51.308(e). In identifying sources subject to BART, the Haze Rule calls for states to use a group rather than a source-by-source approach. See 64 Fed. Reg. at 35,740 (providing that a state should find a source subject to BART "if it can be shown that the source emits pollutants within a geographic area from which pollutants can be emitted and transported downwind to a Class I area") (italics added). In 

addition, when establishing emission limits for consider the improvement in visibility that wouused at all comparable BART sources (rather thparticular device at a particular source would ac51.308(e)(1)(ii)(B).  The various petitioners and intervenors in tnumerous challenges to the Haze Rule. In Part acted contrary to law in establishing a group ratapproach to BART determinations. In Part III wpetitioners in Case Nos. 01-1111, 01-1112, and legal authority and in an arbitrary and capriciou"natural visibility" goal and the "no degradationhaze regulations. Finally, in Part IV, we addresSierra Club - namely that EPA failed to set reasassuring reasonable progress, and that EPA actethe statutory deadline for submission of state ha

II. BART Issue

 Under s 169A of the Act, each state must remeaning all major stationary sources built betw1977 - to determine whether the sources emit "areasonably be anticipated to cause or contribute in a Class I area.2 42 U.S.C. s 7491(b)(2)(A). A

eligible source emits a pollutant which may reacontribute to Class I visibility impairment, the sthe best available retrofit technology for contro

See id. Under the Act, states must take the folloconsideration when deciding what BART contro the costs of compliance, the energy and non

impacts of compliance, any existing pollutithe source, the remaining useful life of the improvement in visibility which may reasofrom the use of such technology. 

2 A "major stationary source" is a source that ha

or more of any pollutant. See 42 U.S.C. s 7491
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Id. s 7491(g)(2).  The Haze Rule interprets and implements these statutory BART provisions in two main ways. First, the Haze Rule requires states to "find that a BARTeligible source is 'reasonably anticipated to cause or contribute' to regional haze if it can be shown that the source emits pollutants within a geographic area from which pollutants can be emitted and transported downwind to a Class I area." 64 Fed. Reg. at 35,740 (italics added). In other words, states must subject BARTeligible sources to BART requirements even absent empirical evidence of that source's individual contribution to visibility impairment in a Class I area so long as the source is located within a region that may contribute to visibility impairment. See id. at 35,740; see also Br. for EPA at 26-27. EPA explained in the preamble to the Haze Rule that this sort of "collective contribution" approach 

was "consistent with that taken in the programs for acid rain and ozone, programs which also address regional air quality problems caused by transported pollutants." 64 Fed. Reg. at 35,740; see also 63 Fed. Reg. at 57,376.  Second, the Haze Rule provides that once a state has decided that a particular source is subject to BART and is considering what BART controls to place on that source, the state must analyze "the degree of visibility improvement that would be achieved in each mandatory Class I Federal area as a result of the emission reductions achievable from all sources subject to BART located within the region that contributes to visibility impairment in the Class I area." 40 C.F.R. s 51.308(e)(1)(ii)(B) (italics added). This means that of the five statutory factors to be considered by states when deter-mining BART controls, see 42 U.S.C. s 7491(g)(2), only four factors (the costs of compliance, the environmental impacts of compliance, any existing pollution control technology in use at the source, and the remaining useful life of the source) are considered on a source-specific basis. The Haze Rule re-quires states to consider the fifth statutory factor (the degree in improvement) on a group or "area wide" basis.  Industry petitioners attack EPA's decision to use a group rather than a source-by-source BART approach, arguing that the language, statutory structure, and legislative history of s 169A make it clear that the Haze Rule runs afoul of the Act. See Br. for Industry Pet'rs and Intervenor in Case Nos. 99-1348, et al. at 13. For the reasons that follow, we grant the petition for review, vacate the BART rules, and remand to EPA.  In the Haze Rule, EPA extracts one of the five statutory factors listed in s 169A(g)(2) and treats it differently than the other four. See 64 Fed. Reg. at 

35,741 (providing that only "the degree in imprbe expect-ed at each Class I area as a result of iconsidered on a group rather than a source-specbifurcates the states' determination of the approfor specific sources. States must first estimate source-by-source basis based on the application for compliance, energy and nonair environmentuseful life of the source. See id.; see also 40 C"Taking these factors into account allows the St'best system' of retrofit control technology for a at 35,741. States must then calculate the degree would be expected at each Class I area as a resusources subject to BART. See id.; see also 40  EPA argues that its bifurcated approach to controls is permissible because s 169A(g)(2) is analyze anticipated visibility improvement. See Res. Def. Council, 467 U.S. 837, 842-43 (1984)Rule's splitting of the statutory factors is consisstructure of the statute. See 42 U.S.C. s 7491(gfactors inform the states' inquiries into what BAparticular sources. Al-though no weights were to be considered together by the states. The lanread in no other way. To treat one of the five stdramatically different fashion distorts the judgmto make for each BART-eligible source. This ithe states' duty to take into account "the costs oonly whether to order an individual source to inequipment, but also what type of equipment - oof "retrofit technology." How is a state to deteris not) for a particular source? The statute answthe degree of improvement in visibility in natiothat would result from the source's installing antechnology. EPA has a far different answer: in imposed on a source, the state may not consider equipment at a particular source would help curnational park. Under EPA's take on the statute, that a source may be forced to spend millions o
P:\23\62\833 - MPCA Tac BART\Task 2\Task 2B\ACGA vs. EPA.DOC 5 

will have no appreciable effect on the haze in any Class I area. 3A similar 

problem arises when a state considers, as it must, the "existing pollution control technology in use at the source." How is a state to decide whether the source already has installed sufficient devices without determining how much, if at all, the source is contributing to visual impairment in downwind Class I areas? As the industry petitioners correctly note, there is no point during the Haze Rule's 

BART determination "in which it could be demonstrated that the degree of improvement in visibility obtained from installing a particular set of emissions controls at a source with 'exceedingly low' or even merely theoretical visibility impacts is not justified by the cost of BART in light of those low or theoretical impacts." Br. for Industry Pet'rs and Intervenor in Case Nos. 99-1348, et al. at 17-18.  The Haze Rule's treatment of s 169A(g)(2)'s degree-of-improvement calculation is, the industry petitioners argue, not the only respect in which the rule is inconsistent with the Act. As they see it, the Haze Rule also unlawfully constrains the states' statutory authority because under the Act it is the states - not EPA - who must determine which BART-eligible sources should be subject 

3 EPA's rule requires states to consider the cost of compliance in terms of the 

likely emission reductions which would be achieved by the imposition of BART, no matter whether this reduction would enhance visibility in downwind national parks. See 64 Fed. Reg. at 35,741 (explaining that the four factors, including cost, "should be taken into account for each source subject to BART in order to compare tradeoffs between the control efficiencies and costs associated with various control alternatives"). The preamble to the rule provides very little guidance about how states are to calculate the degree of improvement in visibility under the regime EPA contemplates. The preamble tells the states only this:

 To calculate the degree of improvement in visibility that would be expected 

at each Class I area as a result of imposing BARTon all sources subject to 

BART, the State should estimate the possible emissions reductions resulting from the application of BART at all subject sources located within the region that contributes to visibility impairment in the Class I area. The State 

should work on its own or in conjunction with other States, such as a regional planning body, to determine the geographic scope of the region that contributes to each Class I area. The States should consult with one another 

to determine the emission reductions achievable from sources subject to BART in other states. Id. 

to BART. See 42 U.S.C. s 7491(b)(2)(A) (provsource that, "as determined by the State ... emitreasonably be anticipated to cause or contribute shall install and operate the best available retrosee also id. s 7491(g)(2) (listing the factors that consideration" in determining BART controls ( We agree with these petitioners that the Hainconsistent with the Act's provisions giving the BART determinations. See id. s 7491(b)(2)(A)Haze Rule ties the states' hands and forces them sources without any empirical evidence of the pvisibility impairment in a Class I area. See 64 Ffor EPA at 26-27. If the Haze Rule contained swhich a state could exempt a BART-eligible soindividualized contribution determination, then Act would not be violated. But the Haze Rule cSection 169A(c)(1) - on which EPA relies - is a Administrator, with the approval of federal land from BART requirements. See 42 U.S.C. s 749by rule, after notice and opportunity for public stationary source from [the BART requirementssuch source does not or will not, by itself or in emit any air pollutant which may reasonably be to a significant impairment of visibility in any msee also id. s 7491(c)(3). It does not provide ththey can exempt sources based on individual co Our conclusion that the Haze Rule's BART constrain state authority is reinforced by the Coamendments to the Act. See Demby v. Schweik1981). The Report explains:  The agreement clarifies that the State, rathe

identifies the source that impairs visibility identified. 

 In establishing emission limitations for any 

the State shall determine what constitutes "technology" ... in establishing emission lim
P:\23\62\833 - MPCA Tac BART\Task 2\Task 2B\ACGA vs. EPA.DOC 6 

basis to be included in the State implementation plan so as to carryout the requirements of this section. 

H.R. Conf. Rep. No. 95-564 (1977), reprinted in 3 Senate Comm. on Env't and Pub. Works, A legislative History of the Clean Air Act Amendments of 1977, at 535 (1978) [hereinafter "1977 Legislative History"]. The "agreement" to which the Conference Report refers was an agreement to reject the House bill's 

provisions giving EPA the power to determine whether a source contributes to visibility impairment and, if so, what BART controls should be applied to that source. See id. at 533-35. Pursuant to the agreement, language was inserted to make it clear that the states - not EPA - would make these BART determinations. See id. at 533-35; see also H.R. Res. 4151, 95th Cong. (1977), reprinted in 1977 Legislative History at 1985, 2325-30. The Conference Report thus confirms that Congress intended the states to decide which sources impair visibility and what BART controls should apply to those sources. The Haze Rule attempts to deprive the states of some of this statutory authority, in contravention of the Act.  In sum, we conclude that the Haze Rule's BART provisions are contrary to the text, structure and history of s 169A of the Act because the rule isolates s 169A(g)(2)'s benefit calculation and constrains authority Congress conferred on the states. Although petitioners also contended that no concept of a group or area-wide BART determination could ever be consistent with the Act,4 we need 

not decide that broad issue today. We hold only that the Haze Rule's treatment of s 169A(g)(2)'s benefit calculation and its infringement on states' authority under the Act render the BART provisions of the rule impermissible. 

III. The "Natural Visibility" Goal and the "No Degradation" Requirement 

 The industry petitioners in Case Nos. 01-1111, 01-1112, and 01-1113 ("Reconsideration Petitioners") cite four grounds in support of their claim that 

4 The industry petitioners argued that source-by-source BART determinations are 

required by the statute and that no concept of area-wide BART determinations is permissible. See Brief for Industry Pet'rs and Intervenor in Case Nos. 99-1348, et al. at 14 (arguing that s 169A makes it clear that BART determinations "must be made on a source-by-source basis"). Cf. Train v. Natural Res. Def. Council, 421 U.S. 60, 64 (1975) (discussing the history of the Clean Air Act and how the premise of the Act was to give states and local governments responsibility over preventing air pollution "at its source"). 

the "natural visibility" goal and the "no degradaRule should be vacated as "arbitrary and capricaccordance with law: (1) EPA exceeded its autadopted regulations that conflict with the PSD pvisibility" as the goal of the regional haze progrimpermissibly constrain state discretion in requvisibility programs using the "no degradation" rEPA has no authority to impose upon the states visibility" conditions, and thereby restrict the oparticipate in the planning process aimed at addEPA promulgated the Haze Rule without providopportunity for comment. We find no merit in deny industry petitioners' challenge to the "natudegradation" requirement.  Before we turn to the merits of petitioners' EPA's contentions that petitioners' challenge to their claims of inadequate notice are barred becraised before the agency. We find no merit in Eargued that the Haze Rule conflicted with the Pcomments to the agency before the regulations for reconsideration. See Supplemental CommeGroup at 22, reprinted in Joint Appendix ("J.A.Reconsideration of the Regional Haze Regulatio

Regulatory Group & Nation-al Mining Ass'n at Petitioners also sought notice and comment in cthe Haze Rule in their petition for reconsideratiReconsideration of the Regional Haze Rule Suband Economic Development at 11-14, reprinted  On the merits, we reject petitioners' claim t169A to adopt the natural visibility goal. EPA authorization in promulgating the challenged re7491(a)(4). In a case such as this, where  "there is an express delegation of authority 

specific provision of the statute by regulati844, ... any ensuing regulation is binding in defective, arbitrary or capricious in substanstatute. 
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United States v. Mead Corp., 533 U.S. 218, 227 (2001) (foot-note omitted). The natural visibility goal is neither "manifestly contrary to the statute" nor "arbitrary or capricious in substance." Indeed, the goal is an eminently reasonable elucidation of the statute.  The statutory goal enunciated in s 169A(a)(1) is quite clear: "the prevention of any future, and the remedying of any existing, impairment of visibility." 42 U.S.C. s 7491(a)(1). Petitioners argue that a "natural visibility" goal cannot be gleaned from this statutory standard. This claim is specious. Agency regulations that aim to remedy any existing impairment of visibility and prevent any future impairment - as the statute commands - will of necessity aim to achieve a state of natural visibility. There is no material inconsistency between the statutory and regulatory goals, for the latter merely elucidates the former.  The petitioners also claim that Congress did not intend for the statutory goal of s 169A(a) to displace the objectives of the PSD program. Therefore, according to petitioners, the natural visibility goal and the no degradation requirement cannot be squared with the PSD program, because that program recognizes that some impairment of visibility would be acceptable in Mandatory Federal Class I areas. We reject this argument, because EPA has reasonably construed the PSD program and the disputed regional haze rules as complementary regulatory regimes.  There are two things worth noting at the outset. First, the natural visibility goal is not a mandate, it is a goal. As EPA has explained, this goal serves as the foundation for analytical tools to be used by the states to set reasonable progress goals. 64 Fed. Reg. at 35,732-33 Petitioners' claim that the agency is without authority to mandate attainment of the national goal is therefore meritless.  Second, the statute specifically calls for regulations to assure "reasonable progress toward meeting the national goal" of remedying any current and preventing any future impairment of visibility. 42 U.S.C. s 7491(a)(4). The no degradation provision requires implementation plans to "pro-vide for an improvement in visibility for the most impaired days over the period of the implementation plan and ensure no degradation in visibility for the least impaired days over the same period." 40 C.F.R. s 51.308(d)(1). This regulation plainly and permissibly serves to assure the reasonable progress sought by Congress. 

 The PSD program was adopted pursuant to See generally Ala. Power Co. v. Costle, 636 F.2The program generally controls any additional d

establishing maximum allowable increases of careas. See 42 U.S.C. s 7473(b). It is therefore out, that the PSD program may sometimes allow deterioration. EPA, however, has taken pains to and the Haze Rule are not at odds:  Section 169A of the CAA requires the 

ensure that the States revise their implemenmeasures necessary to make reasonable provisibility goal. In addition to the remedyinimpairment, that goal requires the preventioimpairment in mandatory Class I Federal arstrategy to effectuate that goal, the final rulanthropogenic sources of visibility impairmshould take into account the cumulative effsources of air pollution in developing their plan as well as potential new sources. 

 With respect to the comment that EPA 

welfare-based standard which renders other a[s] PSD and NSPS largely superfluous, EP

amended the CAA in 1977 to provide for thaware of both the PSD and NSPS provision

required EPA to issue regulations to addresregional haze rule requires States to take in

emissions from both existing and new sournonstationary sources. This is only one of which Congress has provided for overlappiand NSPS programs both focus on the contstationary sources. EPA believes that the rprovisions are complementary means of im

 Commenters raised a number of specif

interaction of the PSD program and the regasked the EPA to address the relationship oproposed visibility impact limits. All PSD II, or III. The classification of an area dete
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maximum allowable increases, or increment, of air quality deterioration. Only a relatively small increment of air quality deterioration is permissible in Class I areas. These increments are measured over annual, 24-hour, and/or 3-hour aver- aging times. Nowhere, however, does the CAA provide that air quality must be allowed to deteriorate to the full extent allowed by the Class I increments standing alone. To read the statute in that manner would contravene both the general goals of the CAA to "protect and enhance" air quality (see section 101(b)(1)) but the specific long-term goal of section 169A is to eventually remedy existing visibility impairment in Class I areas. Accordingly, we believe that allowing localized air quality increases in the short-term due to the emissions from major new sources subject to PSD is not inconsistent with the regional haze program. The regional haze program is focused on long-term emission decreases from the entire regional emission inventory, comprised of major and minor stationary sources, area sources and mo- bile sources. We expect that long-term emission strategies for regional haze will derive substantial emission decreases from the inventory as a whole, and that these overall strategies will be able to accommodate some localized increases within the framework of a regional decrease. We also note that the overall inventory would decrease in cases where new sources are built that replace older, more polluting sources. Accordingly, we do not see any inherent conflict between the two pro- grams. 

 While the PSD program generally allows for a small increment of air 

quality deterioration in Class I areas, section 165 of the CAA also provides for the additional protection of air quality-related values, "including visibility," in Class I Federal areas beyond that provided by the increments. That is, where the FLM [Federal Land Manager] demonstrates that emissions from a new or modified source will have an adverse impact on air quality-related values (AQRVs), notwithstanding the fact that the emissions from the source do not cause or contribute to concentrations in excess of the increment for a Class I area, "a permit shall not be issued." Section 165(d). Thus, under PSD there can be no in- crease in emissions from the construction or modification of a major stationary source where that increase would result in adverse impacts on AQRVs in a Class I Federal area. 

Responses to Significant Comments on the Notice of Pro-posed Rulemaking s I.F (Apr. 1999), reprinted in J.A. 1062-63. 

 The Government also reminds us that the Pthat [visibility] deterioration occur. Nor does it air quality in general or visibility in particular, vides for issuance of a PSD permit as a matter oagree.  Petitioners cite Alabama Power in an attemexistence of the PSD program effectively bars "regulatory goal. Alabama Power supports no sunoted that "[s]ection 169A is available to protecvisibility is an important characteristic, and the [its] rulemaking authority ... to address this proacknowledging the availability of s 169A, the cview that the visibility program is a supplement  Industry petitioners additionally claim that conflicts with s 169A(g)(1)'s list of factors that determining reasonable progress. Section 169A in determining reasonable progress there s

the costs of compliance, the time necessary and nonair quality environmental impacts ouseful life of any existing source subject to 

42 U.S.C. s 7491(g)(1). Petitioners argue that, could at times involve degradation, the "no degStates' authority to apply the statutory criteria.  As noted above, the statute commands EPA assuring "reasonable progress toward meeting t7491(a)(4). The national goal includes "the preimpairment of visibility." Id. s 7491(a)(1). The simply elucidates "reasonable progress." The rany way alter the list of s 169A(g)(1) criteria. Ido not include "degradation." Therefore, the Stthe no degradation requirement while applying  Next, although the petitioners assert that ththe opportunity of some states to participate in addressing regional haze, we can find no real ev
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This contention certainly offers no ground upon which to vacate the disputed regulations.  Finally, petitioners claim that they did not have fair notice and an adequate opportunity to comment on the regulatory goal of natural visibility, because "EPA provided no notice in its 1997 proposal that it intended to require States to achieve natural visibility conditions." Br. for Reconsideration Pet'rs at 25. Rather, according to petitioners, EPA merely pro-posed regulations patterned on the statutory goal enunciated in s 169A(a)(1), i.e., "'preventing any future, and remedying any existing, impairment of visibility."' Br. for Reconsideration Pet'rs at 25 (quoting old 40 C.F.R. s 51.300(a)(1)). This argument is meritless. As noted above, there is no material inconsistency between the statutory goal enunciated in s 169A(a)(1) and the regulatory goal of "natural visibility." The latter is a "logical outgrowth" of the former. Fertilizer Inst. v. EPA, 935 F.2d 1303, 1311 (D.C. Cir. 1991). There-fore, EPA did not violate any notice and comment requirements in adopting the natural visibility goal as a part of the Haze Rule.  If there is any tension between the Haze Rule and the PSD program, it is EPA's responsibility to harmonize the regulatory requirements. It has done so in a perfectly reasonable fashion. EPA's regulatory harmonization is both consistent with the statute and reasonable. Accordingly, we deny the petitions for review of the natural visibility goal and the no degradation requirement. 

IV. The "Reasonable Progress" Criteria and the Extension of the Statutory 

Deadline 

 While the Industry Petitioners attack the Regional Haze Rule as overstepping EPA's statutory authority, Sierra Club argues that EPA has not gone far enough to meet its statutory responsibilities.  In its first cluster of attacks on the Haze Rule, Sierra Club contends that the 

Rule does not satisfy EPA's responsibility under CAA s 169A(a)(4) to "promulgate regulations to assure ... reasonable progress toward meeting the national [visibility] goal," 42 U.S.C. s 7491(a)(4), its responsibility under CAA s 169B(e)(1) to establish "criteria for measuring 'reasonable progress' toward the national goal," 42 U.S.C. s 7492(e)(1), and its obligation under the Administrative Procedure Act not to act in an "arbitrary or capricious" fashion, 5 U.S.C. s 706 (2)(A). Sierra Club argues that the Haze Rule's requirements for improvement in visibility during the 20 percent most impaired days and for no 

degradation during the 20 percent least impairesee also 64 Fed. Reg. at 35,734, do not qualify and are arbitrary and capricious. Similarly, it athat a state not adopt a rate of improvement thato achieve natural visibility unless the state dem

unreasonable, 40 C.F.R. s 51.308(d)(1)(i)(b), (imandates and lacks "requisite specificity" becaureject the 60 year time frame merely by claimin'reasonable."' Reply Br. for Sierra Club at 5, 8.  We might well consider the latter attack undecision in Part II that the group-BART provisiIf in the future a state does conclude that it neednatural visibility, and if EPA decides to accept time be open to Sierra Club to challenge EPA's capricious. In the meantime, this court will cerreview until the policy in question has sufficienAir Tour Coalition v. FAA, 154 F.3d 455, 472 (Power & Light Co. v. EPA, 145 F.3d 1414, 142 But in any event, our decision to invalidate renders this entire cluster of challenges unripe fprovisions were intimately related to EPA's assachieve the goal of natural visibility, we cannot will retain its current criteria for evaluating reaIf the invalidation of the group-BART provisionefficacy of the remaining elements of the Haze wisdom in some of Sierra Club's complaints andpercentage of days during which there must be increase the specificity of its criteria for reasonuncertainty that our decision creates with respeemerge upon remand, the only prudent course iSierra Club's challenges at this juncture.  Sierra Club's second major attack on the Hadetermination to give states 3 years to file haze "attainment" or "unclassifiable." We are troublappears to contravene express statutory languagregarding group-BART we leave this to EPA to 
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 The Transportation Equity Act for the 21st Century, Pub. L. No. 105-178, 112 Stat. 107, 463 (1998) ("TEA-21"), provides that, for areas designated as "nonattainment" for the new national ambient air quality standard (NAAQS) for fine particulate matter, EPA shall require states to submit haze SIPs 3 years after the area has been so designated. See TEA-21 s 6102(c)(2) (incorporating the 3-year deadline of 42 U.S.C. s 7492(e)(2)). However, TEA-21 also expressly mandates that for any area designated as "attainment" or "unclassifiable" for that standard, EPA "shall require the [SIP] to be submitted 1 year after the area has been so designated." Id. Nonetheless, the Haze Rule permits a state to "choose to defer addressing the [Rule's] core requirements for regional haze ... and the requirements for BART" by submitting a so-called "commitment SIP," containing a "demonstration of ongoing participation in a regional planning process to ad-dress regional haze, and an agreement ... to continue participating," a "description of the regional planning process," and a "list of all BART-eligible sources within the state." 40 C.F.R. s 51.308(c), (c)(1). If a state submits such a commitment SIP, the deadline for submitting a haze SIP is extended from 1 year to 3. Id. s 51.308(c)(2); see Br. for EPA at 87; Br. for Sierra Club at 25.  On its face, this provision of the Haze Rule appears to extend the express statutory deadline for "attainment" and "unclassifiable" areas, an action which is beyond the agency's authority. See Sierra Club v. EPA, 129 F.3d 137, 140 (D.C. Cir. 1997) (holding that EPA cannot establish a "grace period" for compliance when not authorized to do so by the CAA); Sierra Club v. EPA, 719 F.2d 436, 469 (D.C. Cir. 1983) (reversing an EPA implementation plan that would have effectively extended the statutory deadline for state submissions under CAA amendments). The statute requires states to submit, by the 1-year deadline, SIPs "contain[ing] such emission limits, schedules of compliance, and other measures as may be necessary to carry out" the haze regulations. 42 U.S.C. s 7492(e)(2) (incorporated by reference into TEA-21 s 6102(c)(2)). A commitment SIP, which by definition ad-dresses neither the Haze Rule's core requirements for regional haze," nor its "requirements for BART," 40 C.F.R. s 51.308(c), does not appear to satisfy the statutory requirement. Cf. Natural Res. Def. Council, Inc. 

v. EPA, 22 F.3d 1125, 1134 (D.C. Cir. 1994) (hthat EPA cannot satisfy its responsibility to detsubmission complies with the CAA unless the smore than a mere promise to take appropriate bfuture," and that a submission containing nothincannot extend the statutory deadline).  Notwithstanding our doubts about the validto vacate it in light of the uncertainty that our dBART provisions of the Haze Rule will cast up

required of the states. With the Rule and hence altered and subject to revision on remand, the mis simply to remand the dead-line-extension issuagency to reconsider its decision to extend the ddecides what form the substantive requirements take.  Garland, Circuit Judge, concurring in part aClean Air Act, Congress declared a national gothe country's largest national parks and wildernopinion, the court adopts an interpretation of thEnvironmental Protection Agency (EPA) and thwill prevent the achievement of Congress' goal. required by the statutory language, we would of But such an interpretation is not required. To ththe Clean Air Act as permitting the group-BARa reasonable interpretation of the legislative lanour deference under the standard announced in Res. Def. Council, Inc., 467 U.S. 837, 842-43 (concur-ring in most of the court's opinion, I disreaches in Part II. 

A 

 Chevron instructs courts to apply a two-step framework when reviewing an agency's construction of a statute. First, we must ask "whether Congress has directly spoken to the precise question at issue," in which case we "must give effect to the unambiguously expressed intent of Congress." Id. at 842-43. However, if the "statute is silent or ambiguous with respect to the specific issue," we move to the second step and must defer to the agency's interpretation as long 

as it is "based on a permissible construction of Barnhart v. Walton, 122 S.Ct. 1265, 1271-72 (2 My colleagues stop at Chevron's first step, the Clean Air Act (CAA) can be read in only onthe industry petitioners that under the Act, BARtechnology") controls cannot be imposed on a show much that particular source contributes to 
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national park or wilderness area, as well as how much improvement in visibility would result from installing BART controls at that specific source. Op. at 10-11. EPA, by contrast, interprets the Clean Air Act as permitting a collective assessment of the impact that emissions from (and controls on) sources located in upwind regions have on visibility impairment in downwind areas.  Before considering the grounds for the court's decision, it is important to understand why EPA decided to require a collective contribution approach, rather than a tracing of the effects of each individual source's emissions. Congress added s 169A to the Clean Air Act "[i]n response to a growing awareness that visibility was rapidly deteriorating" in major national parks and wilderness areas ("Class I areas"). Chevron U.S.A., Inc. v. EPA, 658 F.2d 271, 272 (5th Cir. 1981). The section establishes a national goal of restoring natural visibility in such areas,1 and expressly instructs EPA to issue regulations to 

"assure ... reasonable progress" toward meet-ing the national goal. 42 U.S.C. s 7491(a)(4). After examining the results of scientific studies, EPA concluded that such reasonable progress was not possible without a collective approach. The record compiled by EPA showed that visibility impairment in Class I areas is caused in large part by long-range transport of combined emissions from multiple sources.2 Although it is practicable to trace emissions from an 

individual source into its surrounding region, and to model the transport of combined pollution from that region to a downwind Class I area,3 it is not 

1 Section 169A declares the national goal to be "the prevention of any future, and 

the remedying of any existing, impairment of visibility in mandatory class I Federal areas." 42 U.S.C. s 7491(a)(1). As the court holds today, agency regulations that aim to accomplish these objectives "will of necessity aim to 

achieve a state of natural visibility." Op. at 16. 

2 See, e.g., Congressional Research Service, Regional Haze: EPA's Proposal to 

Improve Visibility in National Parks and Wilderness Areas 2 (1997) (J.A. at 242); National Academy of Sciences, National Research Council, Protecting Visibility in National Parks and Wilderness Areas 7-8, 196-99 (1993) (J.A. at 362, 456-57) [hereinafter "NAS Report"]. 

3 See Regional Haze Regulations, 64 Fed. Reg. 35,714, 35,718 (July 1, 1999). 

The court does not dispute the reasonableness of, or support for, the latter proposition. Cf. Appalachian Power Co. v. EPA, 135 F.3d 791, 802 (D.C. Cir. 1998) (noting that "computer models are a useful and often essential tool for performing the Herculean labors Congress imposed on EPA in the Clean Air Act," and that "their scientific nature does not easily lend itself to judicial 

possible to trace emissions from an individual sdownwind area without great time and expense4 

would be of uncertain reliability.5 Citing the N

conclusion that a program focused "on deter-miindividual emission sources to visibility impairm

EPAadopted the group-BART approach that is 

review" (internal quotation marks omitted)); idEPA's use of computer models proceeds with coagency's expertise."). 4 See NAS Report at 240-41 (J.A. at 478) ("It w

consuming and expensive to try to determine thindividual sources to haze one source at a time.64 Fed. Reg. at 35,740 ("[E]stablishing the consource to the problem of regional haze would restudies and pose substantial technical difficultie

5 See NAS Report at 2 (J.A. at 359) ("During tr

sources mix together to form a uniform, widesphaze."); id. at 20 (J.A. at 368) ("[T]he extent to techniques can be used in attributing visibility itheir usefulness in estimating the effect that difhave on visibility."); id. at 25-26 (J.A. at 370-7particular source is contributing to regional hazobstacles. Studies designed to estimate the effesurrounding visibility are expensive, and the recontroversial."). To take just one example, "the of the Navajo Generating Station to haze in the took several years and cost millions of dollars wdefinitive answers." Id. at 7 (J.A. at 361). 

6EPA, Resp. to Pets. for Recons. of Regional Haat 17) (quoting NAS Report at 7 (J.A. at 361)); at 478) ("The committee doubts ... that such attrworkable visibility protection program."). 
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 My colleagues do not dispute that we must defer to EPA's expert opinion regarding the impracticability of tracing individual source emissions.7 Rather, 

they conclude that not with-standing EPA's view of the facts, the industry petitioners are correct that the Haze Rule's group-BART provisions violate the plain meaning of the Clean Air Act by: (i) employing a group rather than source-by-source standard in determining the appropriate BART controls for a particular source, and (ii) constraining the authority of the states to make their own BART-related decisions. These two contentions are considered in Parts B and C below. Because I conclude that there is nothing in the Clean Air Act that bars the approach taken by EPA, and that to the contrary the Haze Rule rests on a reasonable interpretation of the statutory language, I would follow the Supreme Court's direction in Chevron and uphold the Rule. 

B 

 As the court notes, the Haze Rule employs a group analysis in making two determinations required by the Clean Air Act: (i) whether a pollution-emitting source is subject to BART requirements at all, and (ii) what kind of BART controls should be placed on a subject source. The industry petitioners contend 

that the Clean Air Act prohibits the use of a group standard in making either of these determinations.  Under the Act, a source is subject to BART requirements, and hence a state implementation plan must require such a source to install BART controls, if it "emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in any [Class I] area." CAA s 169A(b)(2)(A), 42 U.S.C. s 7491(b)(2)(A). Under the Haze Rule, a state must "find that a BART-eligible source is 'reasonably anticipated to cause or contribute' to regional haze if it can be shown that the source emits pollutants within a geographic area from which pollutants can be emitted and transported downwind to a Class I area." Regional Haze Regulations, 64 Fed. Reg. at 35,740. That is, a source is subject to BART requirements, without proof of that source's individual contribution to visibility impairment in a Class I area, as long 

7 See Appalachian Power, 135 F.3d at 801-02 ("Our analysis is guided by the 

deference traditionally given to agency expertise, particularly when dealing with a statutory scheme as unwieldy and science-driven as the Clean Air Act."); see also Husqvarna AB v. EPA, 254 F.3d 195, 199 (D.C. Cir. 2001). 

as the source emits pollutants into an upwind artransported to a down-wind Class I area. Id.  The industry petitioners contend that CAA provides that a source is subject to BART requithe extent to which that particular source contriarea. That section, however, requires states to isource that "emits any air pollutant which may or contribute to any impairment of visibility in 7491(b)(2)(A) (emphasis added). Far from plaireading, the italicized words pile ambiguity upothe reader to adopt the construction favored by Collegiate Dictionary 252 (10th ed. 1996) (defisupply in common with others," or "to give a pa(emphasis added); Central Ariz. Water Conserv(9th Cir. 1993) ("The phrase 'may reasonably be Congress did not intend to require EPA to show source's emissions and all or a specific fraction within a Class I area." (quoting with approval Nin the Grand Canyon: An Evaluation of the WiExperiment 5 (1990))). If a source is one of sevupwind area, and if pollution from that area is tnational park,8 then it can hardly be unreasonab

issued by the source "may reasonably be anticipimpairment in the park.  My colleagues wisely do not accept the ind169A(b)(2) bars a collective determination of wBART. (As discussed in Part C infra, they do crequire the states to employ such a mode of anathe petitioners' contention that to determine the should be imposed on a subject source, a state mparticular source contributes to visual impairmeOp. at 11, as well as the degree of improvement the downwind area if that particular source inst

8 Under the Haze Rule, the state must establish 

the second through the application of computer Regional Haze Regulations, 64 Fed. Reg. at 35,
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Haze Rule, by contrast, provides that once a state has concluded that a particular source is subject to BART requirements, in determining the kind of BART controls to place on the source the state must consider the degree of improvement that would be achieved in the downwind area by imposing BART controls on all subject sources in the contributing upwind area. See 40 C.F.R. s 51.308(e)(1)(ii)(B); Regional Haze Regulations, 64 Fed. Reg. at 35,741.  The industry petitioners rest their contention that the statute unambiguously bars this collective assessment approach on s 169A(g)(2), which states:  [I]n determining best available retrofit technology the State ... shall take 

into consideration [1] the costs of compliance, [2] the energy and nonair quality environ- mental impacts of compliance, [3] any existing pollution control technology in use at the source, [4] the remaining useful life of the source, and [5] the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. 

42 U.S.C. s 7491(g)(2). According to both the industry petitioners and the court, this section requires the state to take into consideration each of the five listed factors on a source-by-source basis. Since the Haze Rule does require sourceby-source consideration of the first four factors, see Regional Haze Regulations, 64 Fed. Reg. at 35,740-41; Op. at 9, the only question is whether such consideration is also required of the fifth factor: "the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology."  There is nothing in the statutory language that requires a source-by-source application of the fifth factor. Section 169A(g)(2) requires an assessment of the degree of improvement that may reasonably be anticipated "from the use of such technology," but it does not say whether that improvement must be from the use of such technology by a single source or by all sources in the upwind area.9

Although the court says that the statute does not permit any of the five factors to be treated differently from any of the others, the statute itself does not say so. Moreover, the first four factors are different in kind from the fifth: the first four 

9 See Regional Haze Regulations, 64 Fed. Reg. at 35,741 ("EPA interprets the 

language 'from the use of such technology' to refer to the application of BART level controls to all sources subject to BART."). 

all go to the cost of imposing controls on a partdetermination of the most cost-effective control Regional Haze Regulations, 64 Fed. Reg. at 35,contrast, goes to the benefit to be derived from controls. In EPA's expert view, that benefit can considering the total benefit that would accrue iused the kind of controls most cost-effective fo The industry petitioners concede that s 169undertake a cost-benefit analysis in deciding thspecify the weight to be accorded to any of the 

is that the state "take into consideration" the fiv7491(g)(2). Because the statute does not speciffactors into consideration, it does not bar EPA fthan source-by-source mode of analysis in consWeyerhaeuser Co. v. Costle, 590 F.2d 1011, 10where "Congress did not mandate any particulafactors EPA is to consider, "it left EPA with disfor the consideration factors, and how much wealso New York v. Reilly, 969 F.2d 1147, 1150 ( Other related provisions of the Clean Air A169A(g)(2) as permitting a region-wide assessmEPA to undertake a study to "identify the classewhich, alone or in conjunction with other sourcanticipated to cause or contribute significantly tU.S.C. s 7491(a)(3) (emphasis added), and s 16regulations promulgated under s 169A take into that study, 42 U.S.C. s 7491(b)(1). Similarly, s conduct research "to identify and evaluate sourcvisibility impairment." 42 U.S.C. s 7492(a)(1) 

10 Reply Br. for Industry Pet'rs at 8 ("Industry P

free to determine the weight and significance to s 169A(g)(2) factors."); see Op. at 10; cf. AmeDonovan, 452 U.S. 490, 510 (1981) ("When Coagency engage in cost-benefit analysis, it has clface of the statute."); Central Ariz., 990 F.2d a"Congress has not required 'cost-benefit' analys
P:\23\62\833 - MPCA Tac BART\Task 2\Task 2B\ACGA vs. EPA.DOC 14 

7492(a)(2). These provisions not only permit, but again appear to invite a groupBART approach.  The court states that "under EPA's take on the statute, it is ... entirely possible that a source may be forced to spend millions of dollars for new technology that will have no appreciable effect on the haze in any Class I area." Op. at 10. In accordance with the statute, however, EPA has structured the Haze Rule to avoid this result. The Rule creates an evidentiary presumption that, if a source emits pollution into an upwind region from which it can be shown that pollution is transported downwind to a Class I area, then it "may reasonably be anticipated" that the source "cause[s] or contribute[s] to" impairment in the Class I area--and hence that limiting the source's emissions will reduce that impairment.11 But the presumption is not irrebuttable. To the contrary, the Haze 

Rule incorporates the exemption provision of s 169A(c)(1), which permits EPA to  exempt any major stationary source from the [BART]requirement of 

subsection (b)(2)(A) of this section, upon his determination that such source does not or will not, by itself or in combination with other sources, emit any air pollutant which may reasonably be anticipated to cause or contribute to a significant impairment of visibility in any mandatory class I Federal area. 

42 U.S.C. s 7491(c)(1); see also 40 C.F.R. ss 51.303, .308(e)(4). Hence, a source that emits pollution into a source region, but that can show that BART 

11 The court does not dispute the reasonableness of this presumption. See 

American Iron & Steel Inst. v. EPA, 115 F.3d 979, 1000 (D.C. Cir. 1997) (holding that it is reasonable for EPA to presume that if a pollutant is present in fish tissue at a level exceeding that set by regulation, then any facility "that 

contributes a pollutant to a body of water [in which the fish swims] ... has the reasonable potential to contribute to that exceedence"); see also Baltimore Gas & Elec. Co. v. Natural Res. Def. Council, Inc., 462 U.S. 87, 103 (1983) (holding that a reviewing court must be "at its most deferential" when the agency is "making predictions, within its area of special expertise, at the frontiers of science"); American Trucking Ass'ns, Inc. v. EPA, 175 F.3d 1027, 1055 (D.C. Cir. 1999) ("[W]e have expressly held that EPA's decision to adopt and set air quality standards need only be based on reasonable extrapolations from some reliable evidence." (internal quotation marks omitted)), rev'd on other grounds sub nom. Whitman v. American Trucking Ass'ns, Inc., 531 U.S. 457 (2001). 

controls are unnecessary because its pollution dimpairment of visibility in a Class I area, will nBART controls.12 All that the Haze Rule does i

polluter, rather than on the state. Moreover, the exemption to a source that does not by itself "or sources" contribute to a significant impairment, again invites the collective-assessment approac Finally, one more provision of s 169A desediscussed in Part A above, s 169A(a)(4) instrucregulations to assure reason-able progress towarestoring natural visibility conditions. 42 U.S.Cfindings indicate that it will not be possible "to statutory interpretation announced today prevaideter-mine, as the court's interpretation requiresis contributing to visual impairment in downwinimprovement in visibility in such areas "that wosource's installing and operating" BART contro4, 5. Indeed, EPA explained that it "avoided inregional haze rule that required the assessment attributed to an individual source because" the Nhad determined that such an approach was "doofor Recons. of Regional Haze Rule 16 (Jan. 10, National Academy of Sciences, National Reseain National Parks and Wilderness Areas 7-8, 1957)). We should not lightly assume that Congreimpracticable to achieve the same statute's statenothing in the language of the Clean Air Act thdefeating construction. 

12 The court correctly notes that under this exem

state that determines whether a source has made however, does not rely on the exemption to ansdiscussed in Part C below, but rather to counter Haze Rule fails to provide a source with the oppmakes no appreciable contribution to visibility for EPA at 29-30, 32. 
P:\23\62\833 - MPCA Tac BART\Task 2\Task 2B\ACGA vs. EPA.DOC 15 

C 

 The industry petitioners' second attack on the Haze Rule marches under the banner of states' rights, but in this case that banner is a false flag. The Rule gives states great leeway to make the BART determinations required by the Clean Air Act, reserving to EPA no more authority than Congress conferred upon the agency. Moreover, as discussed above, the industry petitioners' insistence that both EPA and the states are barred from using group-BART principles will impose an enormous unfunded mandate on the states--requiring 

them to engage in lengthy, expensive, and likely fruitless studies to trace pollutants from specific sources into specific Class I areas.13 It is not surprising, 

therefore, that only a single state has enlisted under the petitioner's banner. Five others have filed briefs in support of EPA, while the balance remain silent.  The industry petitioners attack, as unlawfully constraining state authority, both the provision of the Haze Rule that concerns which sources are subject to BART requirements, and the provision that concerns the kind of BART controls that must be installed on subject sources. With respect to the former, the petitioners emphasize s 169A's declaration that "each major stationary source ... which, as determined by the State ... emits any air pollution which may reasonably be anticipated to cause or contribute to any impairment of visibility" in a Class I area, is subject to BART requirements. 42 U.S.C. s 7491(b)(2)(A) (emphasis added). With respect to the latter, they stress that s 169A requires that each subject source install "the best retrofit technology, as determined by the State," 42 U.S.C. s 7491(b)(2)(A), and that "in determining best available retrofit technology the State ... shall take into consideration" the five factors discussed in Part B above, id. s 7491(g)(2) (emphasis added). By directing the states to employ a group-BART analysis in making these determinations, the industry petitioners contend, and the court agrees, that EPA has unlawfully constrained the states' decision making authority. Op. at 11-13.  The Haze Rule, however, does not contravene the statutory commands italicized above. Under the Rule, it is the state and not EPA that determines which specific sources emit pollution that "may reasonably be anticipated to cause or contribute to" impairment, and hence are subject to BART 

13 See supra notes 4, 5; Br. for Maine, et al. at 10 (protesting that to adopt the 

industry petitioners' interpretation of s 169A(g)(2) "would impose staggering and costly administrative burdens" on the states). 

requirements. All that EPA has done, as explaiinterpret that phrase to include sources that emifrom which pollution is transported to national must determine both that the source emits coverinto which the source emits such pollutants is oreasonably be anticipated to be transported to d51.308(e)(1)(ii); Regional Haze Regulations, 6EPA at 43. Similarly, it is still the state that mustatutory factors and the state that must then detechnology for a particular source. All that EPA Part B, is reasonably interpret the fifth of those analyze the degree of anticipated improvement Haze Regulations, 64 Fed. Reg. at 35,741.  Moreover, the Clean Air Act expressly delemake these kinds of judgments. As already notpromulgate regulations to assure reasonable pronational goal of restoring natural visibility. 42 instructs that those regulations shall "provide guappropriate techniques and methods for implemincluding the provisions governing which sourcrequirements and the kind of BART controls th7491(b)(1). The section likewise directs EPA timplementation plan for a State ... to contain sucompliance and other measures as may be necetoward meeting the national goal" of restoring n7491(b)(2). Similarly, the next section of the Aout [its] regulatory responsibilities" under s 169measuring 'reasonable progress' toward the nati7492(e)(1). These provisions give EPA ample guidelines requiring states to use group-BART sources that are subject to BART requirements sources must install.  My colleagues contend that the Conference Amendments reinforces their view that the Hazstate authority. Op. at 13. But that report is a wChevron step one claim regarding the Act's plairecounts, the report merely states that the confethe State, rather than the Administrator, identifi
P:\23\62\833 - MPCA Tac BART\Task 2\Task 2B\ACGA vs. EPA.DOC 16 

visibility," and that in determining the appropriate BART controls for such a source, "the state shall determine what constitutes 'best available retrofit technology' ... in establishing emission limitations on a source-by-source basis." H.R. Conf. Rep. No. 95-564, at 535 (1977). The report tells us nothing more about the referenced "agreement" than can be gleaned from these quotations, and the quotations themselves do little more than restate the statutory language. Moreover, as noted above, the Haze Rule is consistent with these quotations: under the Rule, it is the state rather than EPA that identifies the sources that impair visibility, and it is the state that determines the best available retrofit technology for each such individual source. All that the group-BART provisions of the Rule do is effectuate EPA's authority to "provide guidelines to the states" for making these determinations regarding particular sources. 42 U.S.C. s 7491(b)(1).14

 As the Clean Air Act repeatedly declares, restoring natural visibility to national parks and wilderness areas is a "nation-al" goal. See id. s 7491(a)(1), (a)(4), (b)(2), (b)(2)(B); id. s 7492(e)(1). It is not surprising, therefore, that while the Act leaves many determinations regarding particular sources to the states, it grants EPA authority to establish national guidelines for the kind of analysis the states must employ in making those determinations.15 Under the 

statute, those guidelines must "assure ... reasonable progress toward meeting the national goal" of restoring natural visibility. Id. s 7491(a)(4). Because EPA has 

14 The court states that the "agreement" referred to in the report was an 

agreement to reject the provisions of an earlier House bill. As there may have been many reasons for rejecting that bill, the "[r]ejection of [the] proposed 

legislation during the course of enactment provides a hazardous basis from which to determine legislative intent," GAO v. GAO Pers. Appeals Bd., 698 F.2d 517, 525 n.52 (D.C. Cir. 1983), and a particularly hazardous foundation for a Chevron step one claim. In any event, the most the court can divine regarding the content of the agreement is that it was to insert language clarifying that the states were to "deter-mine whether a source contributes to visibility impairment and, if so, what BART controls should be applied to that source." Op. at 13. As noted in the text, the Haze Rule leaves both determinations in the hands of the states. 

15 Cf. Appalachian Power Co. v. EPA, 249 F.3d 1032, 1047 (D.C. Cir. 2001) 

(holding that a state's development of its implementation plan under CAA s 110 is not "free of extrinsic legal constraints," including EPA's reasonable construction of CAA s 126). 

reasonably determined that group-BART princiassurance, the provisions of the Haze Rule that permissible exercise of the agency's delegated p

D 

 In sum, there is nothing in the language, strAct that bars EPA from promulgating the groupRule. To the contrary, those provisions represean ambiguous statute," and therefore must be giChristensen v. Harris County, 529 U.S. 576, 58U.S. at 842-844). Accordingly, I respectfully dstrike down those provisions. 
ATTACHMENT H 

September 8, 2003, Federal Register Notice – Proposed Consent Decree 

For BART Rule Promulgation Deadlines 
52922 Federal Register / Vol. 68, No. 173 / Monday, September 8, 2003 / Notices 

1Section 169B(e)(1) of the CAA requires EPA to 

issue regional haze rules within 18 months of the 

receipt of the final report of the Grand Canyon 

Visibility Transport Commission. This report was 

received by EPA on June 10, 1996.

1Alliance for Sustainable Communities, Applied 

Power Technologies, Bio Fuels America, California 

Solar Energy Industries Association, Clements 

Environmental Corporation, Environmental 

Advocates, Environmental and Energy Study 

Institute, Friends of the Earth, Full Circle Energy 

Project, Green Party of Rhode Island, Greenpeace 

USA, Network for Environmental and Economic 

Responsibility of the United Church of Christ, New 

Jersey Environmental Watch, New Mexico Solar 

Counsel, phone 202–502–8947, e-mail: 

gordon.wagner@ferc.gov.

Magalie R. Salas, 

Secretary.

[FR Doc. 03–22720 Filed 9–5–03; 8:45 am] 

BILLING CODE 6717–01–P

ENVIRONMENTAL PROTECTION 

AGENCY

[FRL–7555–1]

Proposed Consent Decree, Clean Air 

Act Citizen Suit

AGENCY: Environmental Protection 

Agency (EPA).

ACTION: Notice of proposed Consent 

Decree; request for public comment. 

SUMMARY: In accordance with section 

113(g) of the Clean Air Act, as amended 

(‘‘Act’’), 42 U.S.C. 7413(g), notice is 

hereby given of a proposed Consent 

Decree. On August 15, 2003, 

Environmental Defense filed a 

complaint pursuant to section 304(a) of 

the Act, 42 U.S.C. 7604(a), alleging that 

the Environmental Protection Agency 

had failed to meet its mandatory duty to 

promulgate guidelines and requirements 

for Best Available Retrofit Technology 

(‘‘BART’’) for certain major stationary 

sources. Environmental Defense v.

Marianne Lamont Horinko, No.

1:03CV01737 RMU (D.D.C.). On August 

19, 2003, the United States 

Environmental Protection Agency 

lodged the proposed Consent Decree 

with the United States District Court for 

the District of Columbia Circuit. The 

proposed Consent Decree establishes a 

time frame for EPA to promulgate the 

BART regulations and guidelines.

DATES: Written comments on the 

Proposed Consent decree must be 

received by October 8, 2003.

ADDRESSES: Written comments should 

be sent to M. Lea Anderson, Air and 

Radiation Law Office (2344A), Office of 

General Counsel, U.S. Environmental 

Protection Agency, 1200 Pennsylvania 

Ave., NW., Washington, DC 20460. 

Copies of the proposed Consent Decree 

are available from Phyllis J. Cochran, 

(202) 564–5566.

SUPPLEMENTARY INFORMATION:

Environmental Defense alleges that EPA 

failed to promulgate BART regulations 

and guidelines by the Congressionallyenacted deadline. 

Pursuant to sections 169A and 169B 

of the Clean Air Act, EPA promulgated 

regulations on July 1, 1999 to protect 

visibility in Federal Class I areas. 64 FR 

35714 (‘‘regional haze rule’’). In 

addition, pursuant to section 169A(b), 

EPA proposed to promulgate guidelines 

for the implementation of the BART 

requirements of the regional haze rule 

on July 20, 2001, 66 FR 38108, but has 

not published final guidelines. The 

regional haze rule was challenged, and 

on May 24, 2002, the United States 

Court of Appeals for the District of 

Columbia Circuit (‘‘D.C. Circuit’’)

vacated and remanded to EPA the BART 

provisions of the regional haze rule. 

American Corn Growers Assoc. v. EPA,

291 F.3d 1 (D.C. Cir. 2002). 

Section 169B(e) of the CAA provides 

that EPA must carry out its regulatory 

responsibilities under section 169A of 

the Act to promulgate regulations to 

protect visibility by December 10, 

1997.1 These regulations must require 

each applicable implementation plan to 

contain measures to assure reasonable 

progress toward the national visibility 

goal, including requirements that 

certain major stationary sources 

procure, install, and operate BART. 

CAA section 169A(b)(2). The CAA also 

requires EPA to provide guidelines to 

the States on the implementation of the 

visibility program, including guidelines 

for the determination of BART emission 

limits for fossil-fuel fired generating 

plants with a total generating capacity 

in excess of 750 megawatts. CAA 

section 169A(b).

The Consent Decree provides that 

EPA will sign a notice of proposed 

rulemaking setting forth its proposed 

BART regulations and guidelines no 

later than April 15, 2004. It further 

provides that EPA will submit the 

notice of proposed rulemaking to the 

Office of Federal Register no later than 

five days following signature. The 

Decree also provides that EPA shall sign 

a final notice of rulemaking setting forth 

its BART regulations and guidelines no 

later than April 15, 2005, and that EPA 

will submit the notice of final 

rulemaking to the Office of Federal 

Register no later than five days 

following signature. 

For a period of thirty (30) days 

following the date of publication of this 

notice, the Agency will receive written 

comments relating to the proposed 

Consent Decree from persons who were 

not named as parties or interveners to 

the litigation in question. EPA or the 

Department of Justice may withdraw or 

withhold consent to the proposed 

Consent Decree if the comments 

disclose facts or considerations that 

indicate that such consent is 

inappropriate, improper, inadequate, or 

inconsistent with the requirements of 

the Act. Unless EPA or the Department 

of Justice determine, following the 

comment period, that consent is 

inappropriate, the Consent Decree will 

be final.

Dated: August 22, 2003. 

Lisa K. Friedman, 

Associate General Counsel.

[FR Doc. 03–22769 Filed 9–5–03; 8:45 am] 

BILLING CODE 6560–50–P

ENVIRONMENTAL PROTECTION 

AGENCY

[FRL–7554–7]

Control of Emissions From New 

Highway Vehicles and Engines

AGENCY: Environmental Protection 

Agency (EPA).

ACTION: Notice of denial of petition for 

rulemaking.

SUMMARY: A group of organizations 

petitioned EPA to regulate emissions of 

carbon dioxide and other greenhouse 

gases from motor vehicles under the 

Clean Air Act. For the reasons set forth 

in this notice, EPA is denying the 

petition.

EFFECTIVE DATE: September 8, 2003.

ADDRESSES: Information relevant to this 

action is contained in Docket No. A–

2000–04 at the EPA Docket Center, 

Public Reading Room, Room B102, EPA 

West Building, 1301 Constitution 

Avenue, NW., Washington, DC. Dockets 

may be inspected at this location from 

8:30 a.m. to 4:30 p.m., Monday through 

Friday, except on Government holidays. 

You can reach the Air Docket by 

telephone at (202) 566–1742 and by 

facsimile at (202) 566–1741. You may be 

charged a reasonable fee for 

photocopying docket materials, as 

provided in 40 CFR part 2.

FOR FURTHER INFORMATION CONTACT:

Chitra Kumar, Office of Air and 

Radiation, (202) 564–1389.

SUPPLEMENTARY INFORMATION:

I. Background 

On October 20, 1999, the International 

Center for Technology Assessment 

(ICTA) and a number of other 

organizations 1 petitioned EPA to 

ATTACHMENT I 

Model BART Cost Analysis - Induration Furnace NOx Emissions 

List of Tables: 

Table I-1: BART Screening Evaluation Summary: Straight Grate Induration - SCR 

Table I-2: BART Screening Evaluation Summary: Grate/Kiln Induration - SCR 

Table I-3: BART Screening Evaluation Summary: Straight Grate and Grate/Kiln Induration - LNB and 

UNLB 

Table I-4: Selective Catalytic Reduction - Straight Grate Induration - NOx 

Table I-5: Selective Catalytic Reduction - Grate/Kiln Induration - NOx (50-ppm) 

Table I-6: Selective Catalytic Reduction - Grate/Kiln Induration - NOx (175-ppm) 

Table I-7: Selective Non-Catalytic Reduction - Straight Grate Induration - NOx 

Table I-8: Selective Non-Catalytic Reduction - Grate/Kiln Induration - NOx (50-ppm) 

Table I-9: Selective Non-Catalytic Reduction - Grate/Kiln Induration - NOx (175-ppm) 

Table I-10: Pre Heat Low NOx Burner - Straight Grate Induration 

Table I-11: Pre Heat Ultra Low NOx Burner - Straight Grate and Grate/Kiln Induration 

Table I-12: Selective Catalytic Reduction - Straight Grate Induration with Duct Burner - NOx 

Table I-12.1: Selective Catalytic Reduction - Duct Burner for Straight Grate Induration 

Table I-13: Selective Catalytic Reduction - Grate/Kiln Induration with Duct Burner - NOx (50-ppm) 

Table I-13.1: Selective Catalytic Reduction - Duct Burner for Grate/Kiln Induration - NOx 

Table I-14: Selective Catalytic Reduction - Grate/Kiln Induration with Duct Burner - NOx (175-ppm) 

Table I-14.1: Selective Catalytic Reduction - Duct Burner for Grate/Kiln Induration – NOx 

Table I-15: LTO Scrubber - Grate/Kiln Induration - NOx (50-ppm) 

Table I-16: LTO Scrubber - Grate/Kiln Induration - NOx (175-ppm) 
MPCA BART Analysis 2003

Table I-1: BART Screening Evaluation Summary: Straight Grate Induration 

Model Source for Straight Grate Waste Gas Exhaust - NOx Emissions

General InformationSource Type Straight Grate Waste Gas ExhaustPollutant: NOxExisting Pollution Control Equipment NoneControl Cost Summary Control Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed Capital 

Cost 

(SCR & Burner) 

$

Annualized 

Operating Cost 

$/yr

Pollution 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

SCR on Ind Duct

 1 yr catalyst life 2,397,513 1,103,603 3,959

2 yr catalyst life 2,397,513 841,182 3,018

SCR Add on Control

 2 yr catalyst life 90% 309.7 278.7 3,720,873 2,622,367 9,408 NH3 Emissions 

Comments

NH3 

Emissions 

90% 309.7 278.7

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate NOx Summary 
MPCA BART Analysis 2003

Table I-2: BART Screening Evaluation Summary: Grate/Kiln Induration - 

Model Source for Grate/Kiln Waste Gas Exhaust - NOx Emissions

General InformationSource Type Grate/Kiln Waste Gas ExhaustPollutant: NOxExisting Pollution Control Equipment NoneControl Cost Summary 50 PPM NOx Case

Control Technology

Control 

Eff % Emissions T/y

Emission 

Reduction 

T/yr

Installed Capital 

Cost 

(SCR & Burner) 

$

Annualized 

Operating Cost 

$/yr

Pollution 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

SCR on Ind Duct

 1 yr catalyst life 4,181,322 2,036,612 5,846

2 yr catalyst life 4,181,322 1,511,770 4,339

SCR Add on Control

 2 yr catalyst life 90% 387.1 348 5,755,072 4,878,940 14,004 NH3 Emissions 

CommentsControl Cost Summary 175 PPM NOx Case

Control Technology

Control 

Eff % Emissions T/y

Emission 

Reduction 

T/yr

Installed Capital 

Cost 

(SCR & Burner)

 $

Annualized 

Operating Cost 

$/yr

Pollution 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

SCR on Ind Duct

 1 yr catalyst life 4,181,322 2,169,600 1,779

2 yr catalyst life 4,181,322 1,644,758 1,349

SCR Add on Control

 2 yr catalyst life 90% 1,354.9 1,219 5,755,072 5,011,928 4,110 NH3 Emissions 

Comments

90% 1,354.9 1,219.4 NH3 Emissions 90% 387.1 348.4 NH3 Emissions

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate-Kiln NOx Summary 
MPCA BART Analysis 2003

Table I-3: BART Screening Evaluation Summary: Straight Grate and Grate/Kiln Induration - LN

Model Source for Straight Grate and Grate/Kiln Waste Gas Exhaust - NOx Emissions

Preheat Induced Fuel-Gas Recirculation & Pre Heat Low NOx Burners

General Information

Grate/Kiln Waste Gas ExhaustStraight Grate Waste Gas Exhaust

Pollutant: NOxExisting Pollution Control Equipment NoneControl Cost Summary Pre Heat Low NOx BurnersControl Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed 

Capital Cost $

Annualized 

Operating 

Cost $/yr

Pollution 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Pre Heat IFGR Burners

50% 75.6 37.8 611,448 242,174 6,407 No No 

Pre Heat Low NOx 

Burners 25% 75.6 18.9 369,171 197,614 10,456 No No 

Comments

Source Type

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls LNB and ULNB NOx Summary 
MPCA BART Analysis 2003

Table I-4a: Selective Catalytic Reduction - Straight Grate Induration - NOx 1 yr SCR Catalyst Life

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 1,210,590

Instrumentation 10% of control device cost (A) 121,059

MN Sales Taxes 6.5% of control device cost (A) 78,688

Freight 5% of control device cost (A) 60,530

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 1,470,867

Installation

Foundations & supports 8% of purchased equip cost (B) 117,669

Handling, erection 14% of purchased equip cost (B) 205,921

Electrical 4% of purchased equip cost (B) 58,835

Piping 4% of purchased equip cost (B) 58,835

Insulation 1% of purchased equip cost (B) 14,709

Painting 1% of purchased equip cost (B) 14,709

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 470,677

Total Direct Capital Cost 1,941,544

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 147,087

Construction, field exp. 5% of purchased equip cost (B) 73,543

Construction fee 10% of purchased equip cost (B) 147,087

Startup 2% of purchased equip cost (B) 29,417

Tests 1% of purchased equip cost (B) 14,709

Contingencies 3% of purchased equip cost (B) 44,126

Total Indirect Capital Costs 31% 455,969

Total Capital Investment (TCI) 2,397,513

Replacement Parts Cost & Installation Labor 506,448 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 1,891,065

Total Annualized Capital Costs 178,503

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 509 kW-hr, 8000 hr/yr, 90.0% of capacity 187,277

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Anhydrous Ammonia) 405.00 $/Ton, 32.1 lb/hr, 8000 hr/yr, Ammonia 47,755

 Reagent #2 (Urea 50% Solution) NA - 

 Solid Waste Disposal 25.00 $/Ton, 50.7 ton/yr 1,268

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst 156.72 $/ft3, 2,898.2 ft3, 1, 8000 hr/yr, 90.0% of capacity 541,899

 Replacement Parts NA - 

Total Annual Direct Operating Costs 810,074

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 23,975

Insurance (1% total capital costs) 1% of total capital costs (TCI) 23,975

Administration (2% total capital costs) 2% of total capital costs (TCI) 47,950

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 293,529

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,103,603

Pollutant Removed (tons/yr) 279

Cost per ton of NOx Removed 3,959

Notes & Assumptions

1 Equipment cost estimates obtained from cost curve created from Born Environmental SCR cost estimate dated, 2001 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover ammonia piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Maks sure bed temp > 610 Deg F to min sulfate formation

6 Specify large passage size for catalyst bed. Include soot blowing mechanism & ID any cleaning practices needed

7 Make sure bed temp > 610 Deg F to min sulfate formation

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate - SCR 1yr Page 4 of 44
MPCA BART Analysis 2003

Table I-4a: Selective Catalytic Reduction - Straight Grate Induration - NOx 1 yr SCR Catalyst Life (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 1 years Catalyst Disposal Amount in Tons/yr at 35 lb/ft3

CRF 1.0700 Amount Yrs Service T/yr Waste

Catalyst cost per unit 156.72 $/ft3 50.7 1 50.7

Amount Required 2898.2 ft3

Catalyst Cost 506,448 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 506,448

Annualized Cost 541,899

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 506,448

Design Flow 150,000 dscfm scfm 170,455

135 Temp Deg F

12% % Moisture

188,865 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 508.9 kW-hr 4,071,246 187,277 $/kW-hr, 509 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 32.1 lb/hr 235,828 47,755 $/Ton, 32.1 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 0.0 lb/hr 0 0 $/Lb, 0.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 50.7 ton/yr 51 1,268 $/Ton, 50.7 ton/yr

Haz W Disp 273 Ton 0.000 ton/2-yr period 0.00 0 $/Ton, 80.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 156.72 ft3 2898.2 ft3 1 541,899 $/ft3, 2,898.2 ft3, 1, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 0 $/$/bag, 0.0 bags, 2, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

80.0 ppm 150,000 dscfm NA 310

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

90% 30.97 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 279

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 188,865 11.4 0.55 0.9 508.9 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.05 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 508.9

Ammonia 77.4 lb/hr NOx 0.370 lb NH3/lb NOx 32.1 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 77.4 lb/hr NOx 1.317 lb Urea Sol'n/lb NOx 114.5 lb/hr Urea Sol'n; inlcudes 12.5 lb/hr for NH3 slip

Estimating amount of catalyst required 

Vol. #1 5513 ft3

Flow #1 359256 acfm

Flow #2 188,865 

Vol #2 2898.2 ft3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate - SCR 1yr Page 5 of 44
MPCA BART Analysis 2003

Table I-4b: Selective Catalytic Reduction - Straight Grate Induration - NOx 2 yr SCR Catalyst Life

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 1,210,590

Instrumentation 10% of control device cost (A) 121,059

MN Sales Taxes 6.5% of control device cost (A) 78,688

Freight 5% of control device cost (A) 60,530

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 1,470,867

Installation

Foundations & supports 8% of purchased equip cost (B) 117,669

Handling, erection 14% of purchased equip cost (B) 205,921

Electrical 4% of purchased equip cost (B) 58,835

Piping 4% of purchased equip cost (B) 58,835

Insulation 1% of purchased equip cost (B) 14,709

Painting 1% of purchased equip cost (B) 14,709

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 470,677

Total Direct Capital Cost 1,941,544

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 147,087

Construction, field exp. 5% of purchased equip cost (B) 73,543

Construction fee 10% of purchased equip cost (B) 147,087

Startup 2% of purchased equip cost (B) 29,417

Tests 1% of purchased equip cost (B) 14,709

Contingencies 3% of purchased equip cost (B) 44,126

Total Indirect Capital Costs 31% 455,969

Total Capital Investment (TCI) 2,397,513

Replacement Parts Cost & Installation Labor 506,448 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 1,891,065

Total Annualized Capital Costs 178,503

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 509 kW-hr, 8000 hr/yr, 90.0% of capacity 187,277

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Anhydrous Ammonia) 405.00 $/Ton, 32.1 lb/hr, 8000 hr/yr, Ammonia 47,755

 Reagent #2 (Urea 50% Solution) NA - 

 Solid Waste Disposal 25.00 $/Ton, 25.4 ton/yr 634

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst 156.72 $/ft3, 2,898.2 ft3, 2, 8000 hr/yr, 90.0% of capacity 280,112

 Replacement Parts NA - 

Total Annual Direct Operating Costs 547,653

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 23,975

Insurance (1% total capital costs) 1% of total capital costs (TCI) 23,975

Administration (2% total capital costs) 2% of total capital costs (TCI) 47,950

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 293,529

Total Annual Cost (Annualized Capital Cost + Operating Cost) 841,182

Pollutant Removed (tons/yr) 279

Cost per ton of NOx Removed 3,018

Notes & Assumptions

1 Equipment cost estimates obtained from cost curve created from Born Environmental SCR cost estimate dated, 2001 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover ammonia piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Maks sure bed temp > 610 Deg F to min sulfate formation

6 Specify large passage size for catalyst bed. Include soot blowing mechanism & ID any cleaning practices needed

7 Make sure bed temp > 610 Deg F to min sulfate formation

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate - SCR 2yr Page 6 of 44
MPCA BART Analysis 2003

Table I-4b: Selective Catalytic Reduction - Straight Grate Induration - NOx 2 yr SCR Catalyst Life (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years Catalyst Disposal Amount in Tons/yr at 35 lb/ft3

CRF 0.5531 Amount Yrs Service T/yr Waste

Catalyst cost per unit 156.72 $/ft3 50.7 2 25.4

Amount Required 2898.2 ft3

Catalyst Cost 506,448 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 506,448

Annualized Cost 280,112

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 506,448

Design Flow 150,000 dscfm scfm 170,455

135 Temp Deg F

12% % Moisture

188,865 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 508.9 kW-hr 4,071,246 187,277 $/kW-hr, 509 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 32.1 lb/hr 235,828 47,755 $/Ton, 32.1 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 0.0 lb/hr 0 0 $/Lb, 0.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 25.4 ton/yr 25 634 $/Ton, 25.4 ton/yr

Haz W Disp 273 Ton 0.000 ton/2-yr period 0.00 0 $/Ton, 80.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 156.72 ft3 2898.2 ft3 2 280,112 $/ft3, 2,898.2 ft3, 2, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 0 $/$/bag, 0.0 bags, 2, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

80.0 ppm 150,000 dscfm NA 310

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

90% 30.97 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 279

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 188,865 11.4 0.55 0.9 508.9 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.05 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 508.9

Ammonia 77.4 lb/hr NOx 0.370 lb NH3/lb NOx 32.1 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 77.4 lb/hr NOx 1.317 lb Urea Sol'n/lb NOx 114.5 lb/hr Urea Sol'n; inlcudes 12.5 lb/hr for NH3 slip

Estimating amount of catalyst required 

Vol. #1 5513 ft3

Flow #1 359256 acfm

Flow #2 188,865 

Vol #2 2898.2 ft3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate - SCR 2yr Page 7 of 44
MPCA BART Analysis 2003

Table I-5a: Selective Catalytic Reduction - Grate/Kiln Induration - NOx (50-ppm) 1 yr SCR Catalyst Life

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 2,111,299

Instrumentation 10% of control device cost (A) 211,130

MN Sales Taxes 6.5% of control device cost (A) 137,234

Freight 5% of control device cost (A) 105,565

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 2,565,228

Installation

Foundations & supports 8% of purchased equip cost (B) 205,218

Handling, erection 14% of purchased equip cost (B) 359,132

Electrical 4% of purchased equip cost (B) 102,609

Piping 4% of purchased equip cost (B) 102,609

Insulation 1% of purchased equip cost (B) 25,652

Painting 1% of purchased equip cost (B) 25,652

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 820,873

Total Direct Capital Cost 3,386,101

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 256,523

Construction, field exp. 5% of purchased equip cost (B) 128,261

Construction fee 10% of purchased equip cost (B) 256,523

Startup 2% of purchased equip cost (B) 51,305

Tests 1% of purchased equip cost (B) 25,652

Contingencies 3% of purchased equip cost (B) 76,957

Total Indirect Capital Costs 31% 795,221

Total Capital Investment (TCI) 4,181,322

Replacement Parts Cost & Installation Labor 1,012,895 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 3,168,427

Total Annualized Capital Costs 299,077

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity 374,554

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Anhydrous Ammonia) 405.00 $/Ton, 39.3 lb/hr, 8000 hr/yr, Ammonia 58,394

 Reagent #2 (Urea 50% Solution) NA - 

 Solid Waste Disposal 25.00 $/Ton, 101.4 ton/yr 2,536

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst 156.72 $/ft3, 5,796.5 ft3, 1, 8000 hr/yr, 90.0% of capacity 1,083,798

 Replacement Parts NA - 

Total Annual Direct Operating Costs 1,551,157

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 41,813

Insurance (1% total capital costs) 1% of total capital costs (TCI) 41,813

Administration (2% total capital costs) 2% of total capital costs (TCI) 83,626

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 485,455

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,036,612

Pollutant Removed (tons/yr) 348

Cost per ton of NOx Removed 5,846

Notes & Assumptions

1 Equipment cost estimates obtained from cost curve created from Born Environmental SCR cost estimate dated, 2001 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover ammonia piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Maks sure bed temp > 610 Deg F to min sulfate formation

6 Specify large passage size for catalyst bed. Include soot blowing mechanism & ID any cleaning practices needed

7 Make sure bed temp > 610 Deg F to min sulfate formation

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR (50) 1yr Page 8 of 44
MPCA BART Analysis 2003

Table I-5a: Selective Catalytic Reduction - Grate/Kiln Induration - NOx (50-ppm) 1 yr SCR Catalyst Life (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 1 years Catalyst Disposal Amount in Tons/yr at 35 lb/ft3

CRF 1.0700 Amount Yrs Service T/yr Waste

Catalyst cost per unit 156.72 $/ft3 101.4 1 101.4

Amount Required 5796.5 ft3

Catalyst Cost 1,012,895 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 1,012,895

Annualized Cost 1,083,798

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 1,012,895

Design Flow 300,000 dscfm scfm 340,909

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1017.8 kW-hr 8,142,488 374,554 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 39.3 lb/hr 288,366 58,394 $/Ton, 39.3 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 0.0 lb/hr 0 0 $/Lb, 0.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 101.4 ton/yr 101 2,536 $/Ton, 101.4 ton/yr

Haz W Disp 273 Ton 0.000 ton/2-yr period 0.00 0 $/Ton, 50.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 156.72 ft3 5796.5 ft3 1 1,083,798 $/ft3, 5,796.5 ft3, 1, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 0 $/$/bag, 0.0 bags, 2, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

50.0 ppm 300,000 dscfm NA 387

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

90% 38.71 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 348

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 377,730 11.4 0.55 0.9 1017.8 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.06 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 1017.8

Ammonia 96.8 lb/hr NOx 0.370 lb NH3/lb NOx 39.3 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 96.8 lb/hr NOx 1.317 lb Urea Sol'n/lb NOx 140.0 lb/hr Urea Sol'n; inlcudes 12.5 lb/hr for NH3 slip

Estimating amount of catalyst required 

Vol. #1 5513 ft3

Flow #1 359256 acfm

Flow #2 377,730 

Vol #2 5796.5 ft3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR (50) 1yr Page 9 of 44
MPCA BART Analysis 2003

Table I-5b: Selective Catalytic Reduction - Grate/Kiln Induration - NOx (50-ppm) 2 yr SCR Catalyst Life

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 2,111,299

Instrumentation 10% of control device cost (A) 211,130

MN Sales Taxes 6.5% of control device cost (A) 137,234

Freight 5% of control device cost (A) 105,565

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 2,565,228

Installation

Foundations & supports 8% of purchased equip cost (B) 205,218

Handling, erection 14% of purchased equip cost (B) 359,132

Electrical 4% of purchased equip cost (B) 102,609

Piping 4% of purchased equip cost (B) 102,609

Insulation 1% of purchased equip cost (B) 25,652

Painting 1% of purchased equip cost (B) 25,652

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 820,873

Total Direct Capital Cost 3,386,101

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 256,523

Construction, field exp. 5% of purchased equip cost (B) 128,261

Construction fee 10% of purchased equip cost (B) 256,523

Startup 2% of purchased equip cost (B) 51,305

Tests 1% of purchased equip cost (B) 25,652

Contingencies 3% of purchased equip cost (B) 76,957

Total Indirect Capital Costs 31% 795,221

Total Capital Investment (TCI) 4,181,322

Replacement Parts Cost & Installation Labor 1,012,895 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 3,168,427

Total Annualized Capital Costs 299,077

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity 374,554

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Anhydrous Ammonia) 405.00 $/Ton, 39.3 lb/hr, 8000 hr/yr, Ammonia 58,394

 Reagent #2 (Urea 50% Solution) NA - 

 Solid Waste Disposal 25.00 $/Ton, 50.7 ton/yr 1,268

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst 156.72 $/ft3, 5,796.5 ft3, 2, 8000 hr/yr, 90.0% of capacity 560,224

 Replacement Parts NA - 

Total Annual Direct Operating Costs 1,026,315

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 41,813

Insurance (1% total capital costs) 1% of total capital costs (TCI) 41,813

Administration (2% total capital costs) 2% of total capital costs (TCI) 83,626

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 485,455

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,511,770

Pollutant Removed (tons/yr) 348

Cost per ton of NOx Removed 4,339

Notes & Assumptions

1 Equipment cost estimates obtained from cost curve created from Born Environmental SCR cost estimate dated, 2001 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover ammonia piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Maks sure bed temp > 610 Deg F to min sulfate formation

6 Specify large passage size for catalyst bed. Include soot blowing mechanism & ID any cleaning practices needed

7 Make sure bed temp > 610 Deg F to min sulfate formation

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR (50) 2yr Page 10 of 44
MPCA BART Analysis 2003

Table I-5b: Selective Catalytic Reduction - Grate/Kiln Induration - NOx (50-ppm) 2 yr SCR Catalyst Life (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years Catalyst Disposal Amount in Tons/yr at 35 lb/ft3

CRF 0.5531 Amount Yrs Service T/yr Waste

Catalyst cost per unit 156.72 $/ft3 101.4 2 50.7

Amount Required 5796.5 ft3

Catalyst Cost 1,012,895 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 1,012,895

Annualized Cost 560,224

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 1,012,895

Design Flow 300,000 dscfm scfm 340,909

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1017.8 kW-hr 8,142,488 374,554 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 39.3 lb/hr 288,366 58,394 $/Ton, 39.3 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 0.0 lb/hr 0 0 $/Lb, 0.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 50.7 ton/yr 51 1,268 $/Ton, 50.7 ton/yr

Haz W Disp 273 Ton 0.000 ton/2-yr period 0.00 0 $/Ton, 50.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 156.72 ft3 5796.5 ft3 2 560,224 $/ft3, 5,796.5 ft3, 2, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 0 $/$/bag, 0.0 bags, 2, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

50.0 ppm 300,000 dscfm NA 387

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

90% 38.71 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 348

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 377,730 11.4 0.55 0.9 1017.8 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.06 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 1017.8

Ammonia 96.8 lb/hr NOx 0.370 lb NH3/lb NOx 39.3 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 96.8 lb/hr NOx 1.317 lb Urea Sol'n/lb NOx 140.0 lb/hr Urea Sol'n; inlcudes 12.5 lb/hr for NH3 slip

Estimating amount of catalyst required 

Vol. #1 5513 ft3

Flow #1 359256 acfm

Flow #2 377,730 

Vol #2 5796.5 ft3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR (50) 2yr Page 11 of 44
MPCA BART Analysis 2003

Table I-6a: Selective Catalytic Reduction - Grate/Kiln Induration - NOx (175-ppm) 1 yr SCR Catalyst Life

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 2,111,299

Instrumentation 10% of control device cost (A) 211,130

MN Sales Taxes 6.5% of control device cost (A) 137,234

Freight 5% of control device cost (A) 105,565

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 2,565,228

Installation

Foundations & supports 8% of purchased equip cost (B) 205,218

Handling, erection 14% of purchased equip cost (B) 359,132

Electrical 4% of purchased equip cost (B) 102,609

Piping 4% of purchased equip cost (B) 102,609

Insulation 1% of purchased equip cost (B) 25,652

Painting 1% of purchased equip cost (B) 25,652

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 820,873

Total Direct Capital Cost 3,386,101

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 256,523

Construction, field exp. 5% of purchased equip cost (B) 128,261

Construction fee 10% of purchased equip cost (B) 256,523

Startup 2% of purchased equip cost (B) 51,305

Tests 1% of purchased equip cost (B) 25,652

Contingencies 3% of purchased equip cost (B) 76,957

Total Indirect Capital Costs 31% 795,221

Total Capital Investment (TCI) 4,181,322

Replacement Parts Cost & Installation Labor 1,012,895 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 3,168,427

Total Annualized Capital Costs 299,077

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity 374,555

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Anhydrous Ammonia) 405.00 $/Ton, 128.8 lb/hr, 8000 hr/yr, Ammonia 191,381

 Reagent #2 (Urea 50% Solution) NA - 

 Solid Waste Disposal 25.00 $/Ton, 101.4 ton/yr 2,536

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst 156.72 $/ft3, 5,796.5 ft3, 1, 8000 hr/yr, 90.0% of capacity 1,083,798

 Replacement Parts NA - 

Total Annual Direct Operating Costs 1,684,145

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 41,813

Insurance (1% total capital costs) 1% of total capital costs (TCI) 41,813

Administration (2% total capital costs) 2% of total capital costs (TCI) 83,626

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 485,455

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,169,600

Pollutant Removed (tons/yr) 1,219

Cost per ton of NOx Removed 1,779

Notes & Assumptions

1 Equipment cost estimates obtained from cost curve created from Born Environmental SCR cost estimate dated, 2001 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover ammonia piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Maks sure bed temp > 610 Deg F to min sulfate formation

6 Specify large passage size for catalyst bed. Include soot blowing mechanism & ID any cleaning practices needed

7 Make sure bed temp > 610 Deg F to min sulfate formation

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR (175) 1yr Page 12 of 44
MPCA BART Analysis 2003

Table I-6a: Selective Catalytic Reduction - Grate/Kiln Induration - NOx (175-ppm) 1 yr SCR Catalyst Life (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 1 years Catalyst Disposal Amount in Tons/yr at 35 lb/ft3

CRF 1.0700 Amount Yrs Service T/yr Waste

Catalyst cost per unit 156.72 $/ft3 101.4 1 101.4

Amount Required 5796.5 ft3

Catalyst Cost 1,012,895 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 1,012,895

Annualized Cost 1,083,798

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 1,012,895

Design Flow 300,000 dscfm scfm 340,909

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1017.8 kW-hr 8,142,502 374,555 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 128.8 lb/hr 945,090 191,381 $/Ton, 128.8 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 0.0 lb/hr 0 0 $/Lb, 0.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 101.4 ton/yr 101 2,536 $/Ton, 101.4 ton/yr

Haz W Disp 273 Ton 0.000 ton/2-yr period 0.00 0 $/Ton, 175.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 156.72 ft3 5796.5 ft3 1 1,083,798 $/ft3, 5,796.5 ft3, 1, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 0 $/$/bag, 0.0 bags, 2, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

175.0 ppm 300,000 dscfm NA 1,355

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

90% 135.49 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 1,219

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 377,730 11.4 0.55 0.9 1017.8 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.20 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 1017.8

Ammonia 338.7 lb/hr NOx 0.370 lb NH3/lb NOx 128.8 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 338.7 lb/hr NOx 1.317 lb Urea Sol'n/lb NOx 458.6 lb/hr Urea Sol'n; inlcudes 12.5 lb/hr for NH3 slip

Estimating amount of catalyst required 

Vol. #1 5513 ft3

Flow #1 359256 acfm

Flow #2 377,730 

Vol #2 5796.5 ft3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR (175) 1yr Page 13 of 44
MPCA BART Analysis 2003

Table I-6a: Selective Catalytic Reduction - Grate/Kiln Induration - NOx (175-ppm) 2 yr SCR Catalyst Life

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 2,111,299

Instrumentation 10% of control device cost (A) 211,130

MN Sales Taxes 6.5% of control device cost (A) 137,234

Freight 5% of control device cost (A) 105,565

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 2,565,228

Installation

Foundations & supports 8% of purchased equip cost (B) 205,218

Handling, erection 14% of purchased equip cost (B) 359,132

Electrical 4% of purchased equip cost (B) 102,609

Piping 4% of purchased equip cost (B) 102,609

Insulation 1% of purchased equip cost (B) 25,652

Painting 1% of purchased equip cost (B) 25,652

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 820,873

Total Direct Capital Cost 3,386,101

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 256,523

Construction, field exp. 5% of purchased equip cost (B) 128,261

Construction fee 10% of purchased equip cost (B) 256,523

Startup 2% of purchased equip cost (B) 51,305

Tests 1% of purchased equip cost (B) 25,652

Contingencies 3% of purchased equip cost (B) 76,957

Total Indirect Capital Costs 31% 795,221

Total Capital Investment (TCI) 4,181,322

Replacement Parts Cost & Installation Labor 1,012,895 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 3,168,427

Total Annualized Capital Costs 299,077

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity 374,555

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Anhydrous Ammonia) 405.00 $/Ton, 128.8 lb/hr, 8000 hr/yr, Ammonia 191,381

 Reagent #2 (Urea 50% Solution) NA - 

 Solid Waste Disposal 25.00 $/Ton, 50.7 ton/yr 1,268

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst 156.72 $/ft3, 5,796.5 ft3, 2, 8000 hr/yr, 90.0% of capacity 560,224

 Replacement Parts NA - 

Total Annual Direct Operating Costs 1,159,303

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 41,813

Insurance (1% total capital costs) 1% of total capital costs (TCI) 41,813

Administration (2% total capital costs) 2% of total capital costs (TCI) 83,626

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 485,455

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,644,758

Pollutant Removed (tons/yr) 1,219

Cost per ton of NOx Removed 1,349

Notes & Assumptions

1 Equipment cost estimates obtained from cost curve created from Born Environmental SCR cost estimate dated, 2001 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover ammonia piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Maks sure bed temp > 610 Deg F to min sulfate formation

6 Specify large passage size for catalyst bed. Include soot blowing mechanism & ID any cleaning practices needed

7 Make sure bed temp > 610 Deg F to min sulfate formation

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR (175) 2 yr Page 14 of 44
MPCA BART Analysis 2003

Table I-6a: Selective Catalytic Reduction - Grate/Kiln Induration - NOx (175-ppm) 2 yr SCR Catalyst Life (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years Catalyst Disposal Amount in Tons/yr at 35 lb/ft3

CRF 0.5531 Amount Yrs Service T/yr Waste

Catalyst cost per unit 156.72 $/ft3 101.4 2 50.7

Amount Required 5796.5 ft3

Catalyst Cost 1,012,895 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 1,012,895

Annualized Cost 560,224

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 1,012,895

Design Flow 300,000 dscfm scfm 340,909

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1017.8 kW-hr 8,142,502 374,555 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 128.8 lb/hr 945,090 191,381 $/Ton, 128.8 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 0.0 lb/hr 0 0 $/Lb, 0.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 50.7 ton/yr 51 1,268 $/Ton, 50.7 ton/yr

Haz W Disp 273 Ton 0.000 ton/2-yr period 0.00 0 $/Ton, 175.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 156.72 ft3 5796.5 ft3 2 560,224 $/ft3, 5,796.5 ft3, 2, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 0 $/$/bag, 0.0 bags, 2, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

175.0 ppm 300,000 dscfm NA 1,355

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

90% 135.49 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 1,219

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 377,730 11.4 0.55 0.9 1017.8 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.20 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 1017.8

Ammonia 338.7 lb/hr NOx 0.370 lb NH3/lb NOx 128.8 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 338.7 lb/hr NOx 1.317 lb Urea Sol'n/lb NOx 458.6 lb/hr Urea Sol'n; inlcudes 12.5 lb/hr for NH3 slip

Estimating amount of catalyst required 

Vol. #1 5513 ft3

Flow #1 359256 acfm

Flow #2 377,730 

Vol #2 5796.5 ft3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR (175) 2 yr Page 15 of 44
MPCA BART Analysis 2003

Table I-7: Selective Non-Catalytic Reduction - Straight Grate Induration - NOx

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) SNCR equipment + duct + grate bays + blower 325,951

Instrumentation 1% of control device cost (A) 3,260

MN Sales Taxes 6.5% of control device cost (A) 21,187

Freight 5% of control device cost (A) 16,298

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 366,695

Installation

Foundations & supports 8% of purchased equip cost (B) 29,336

Handling, erection 14% of purchased equip cost (B) 51,337

Electrical 4% of purchased equip cost (B) 14,668

Piping 4% of purchased equip cost (B) 14,668

Insulation 1% of purchased equip cost (B) 3,667

Painting 1% of purchased equip cost (B) 3,667

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific

Buildings, as required Building extention to for additional grate sections

Installation Total 30% 117,342

Total Direct Capital Cost 484,037

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 36,669

Construction, field exp. 5% of purchased equip cost (B) 18,335

Construction fee 10% of purchased equip cost (B) 36,669

Startup 2% of purchased equip cost (B) 7,334

Tests 1% of purchased equip cost (B) 3,667

Contingencies 3% of purchased equip cost (B) 11,001

Total Indirect Capital Costs 31% 113,675

Total Capital Investment (TCI) 597,713

Replacement Parts Cost & Installation Labor 0 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 597,713

Total Annualized Capital Costs 56,420

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 223 kW-hr, 8000 hr/yr, 90.0% of capacity 82,139

 Natural Gas (Fuel) NA - 

 Water 0.22 $/Mgal, 8.0 gpm, 8000 hr/yr, 90.0% of capacity 845

 Compressed Air 0.27 $/Mscf, 14.0 scfm, 8000 hr/yr, 90.0% of capacity 1,814

 Reagent #1(Anhydrous Ammonia) NA - 

 Reagent #2 (Urea 50% Solution) 0.09 $/Lb, 175.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln. 109,109

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 225,782

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,977

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,977

Administration (2% total capital costs) 2% of total capital costs (TCI) 11,954

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 99,453

Total Annual Cost (Annualized Capital Cost + Operating Cost) 325,235

Pollutant Removed (tons/yr) 217

Cost per ton of NOx Removed 1,500

Notes & Assumptions

1 Equipment cost estimated using 0.6 power factor in conjunction with SNCR cost estimate from Wheelabrator dated 2001. 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover urea piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Equipment cost includes instrumentation. Reduced instrumentation factor from 10% to 1% to account for tie-ins to plant control system

6

7 Make sure bed temp > 610 Deg F to min sulfate formation

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate - SNCR Page 16 of 44
MPCA BART Analysis 2003

Table I-7: Selective Non-Catalytic Reduction - Straight Grate Induration - NOx (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 150,000 dscfm 170,455 scfm

135 Temp Deg F

12% % Moisture

188,865 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 223.2 kW-hr 1,785,637 82,139 $/kW-hr, 223 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 8 gpm 3,840 845 $/Mgal, 8.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 14.0 scfm 6,719,110 1,814 $/Mscf, 14.0 scfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 175.0 lb/hr 1,283,630 109,109 $/Lb, 175.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 80.000 ppm, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/2-yr period 0 0 $/Ton, 80.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

80 ppm 150,000 dscfm NA 310

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

70% 92.91 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 217

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 188,865 5 0.55 0.9 223.2 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Blower 0 5 0.55 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.05 50 0.8 0.9 0.00 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 223.2

Ammonia 77.4 lb/hr NOx 0.370 lb NH3/lb NOx 32.1 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 77.4 lb/hr NOx 2.260 lb Urea Sol'n/lb NOx 175.0 lb/hr Urea Sol'n per vendor quote

Comp Air 0.08 scfm per lb/hr Urea 14.0

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate - SNCR Page 17 of 44
MPCA BART Analysis 2003

Table I-8: Selective Non-Catalytic Reduction - Grate/Kiln Induration - NOx (50-ppm)

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) SNCR equipment + duct + grate bays + blower 494,049

Instrumentation 1% of control device cost (A) 4,940

MN Sales Taxes 6.5% of control device cost (A) 32,113

Freight 5% of control device cost (A) 24,702

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 555,805

Installation

Foundations & supports 8% of purchased equip cost (B) 44,464

Handling, erection 14% of purchased equip cost (B) 77,813

Electrical 4% of purchased equip cost (B) 22,232

Piping 4% of purchased equip cost (B) 22,232

Insulation 1% of purchased equip cost (B) 5,558

Painting 1% of purchased equip cost (B) 5,558

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific

Buildings, as required Building extention to for additional grate sections

Installation Total 30% 177,858

Total Direct Capital Cost 733,663

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 55,581

Construction, field exp. 5% of purchased equip cost (B) 27,790

Construction fee 10% of purchased equip cost (B) 55,581

Startup 2% of purchased equip cost (B) 11,116

Tests 1% of purchased equip cost (B) 5,558

Contingencies 3% of purchased equip cost (B) 16,674

Total Indirect Capital Costs 31% 172,300

Total Capital Investment (TCI) 905,962

Replacement Parts Cost & Installation Labor 0 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 905,962

Total Annualized Capital Costs 85,516

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 446 kW-hr, 8000 hr/yr, 90.0% of capacity 164,278

 Natural Gas (Fuel) NA - 

 Water 0.22 $/Mgal, 8.0 gpm, 8000 hr/yr, 90.0% of capacity 845

 Compressed Air 0.27 $/Mscf, 17.5 scfm, 8000 hr/yr, 90.0% of capacity 2,268

 Reagent #1(Anhydrous Ammonia) NA - 

 Reagent #2 (Urea 50% Solution) 0.09 $/Lb, 218.7 lb/hr, 8000 hr/yr, 50 wt% Urea Soln. 136,386

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 335,652

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 9,060

Insurance (1% total capital costs) 1% of total capital costs (TCI) 9,060

Administration (2% total capital costs) 2% of total capital costs (TCI) 18,119

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 140,880

Total Annual Cost (Annualized Capital Cost + Operating Cost) 476,532

Pollutant Removed (tons/yr) 271

Cost per ton of NOx Removed 1,759

Notes & Assumptions

1 Equipment cost estimated using 0.6 power factor in conjunction with SNCR cost estimate from Wheelabrator dated 2001. 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover urea piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Equipment cost includes instrumentation. Reduced instrumentation factor from 10% to 1% to account for tie-ins to plant control system

6

7 Make sure bed temp > 610 Deg F to min sulfate formation

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SNCR (50) Page 18 of 44
MPCA BART Analysis 2003

Table I-8: Selective Non-Catalytic Reduction - Grate/Kiln Induration - NOx (50-ppm) (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340,909 scfm

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 446.4 kW-hr 3,571,270 164,278 $/kW-hr, 446 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 8 gpm 3,840 845 $/Mgal, 8.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 17.49768 scfm 8,398,888 2,268 $/Mscf, 17.5 scfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 218.7 lb/hr 1,604,538 136,386 $/Lb, 218.7 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 50.000 ppm, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/2-yr period 0 0 $/Ton, 50.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

50 ppm 300,000 dscfm NA 387

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

70% 116.14 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 271

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 377,730 5 0.55 0.9 446.4 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Blower 0 5 0.55 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.06 50 0.8 0.9 0.00 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 446.4

Ammonia 96.8 lb/hr NOx 0.370 lb NH3/lb NOx 39.3 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 96.8 lb/hr NOx 2.260 lb Urea Sol'n/lb NOx 218.7 lb/hr Urea Sol'n per vendor quote

Comp Air 0.08 scfm per lb/hr Urea 17.5

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SNCR (50) Page 19 of 44
MPCA BART Analysis 2003

Table I-9: Selective Non-Catalytic Reduction - Grate/Kiln Induration - NOx (175-ppm)

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) SNCR equipment + duct + grate bays + blower 494,049

Instrumentation 1% of control device cost (A) 4,940

MN Sales Taxes 6.5% of control device cost (A) 32,113

Freight 5% of control device cost (A) 24,702

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 555,805

Installation

Foundations & supports 8% of purchased equip cost (B) 44,464

Handling, erection 14% of purchased equip cost (B) 77,813

Electrical 4% of purchased equip cost (B) 22,232

Piping 4% of purchased equip cost (B) 22,232

Insulation 1% of purchased equip cost (B) 5,558

Painting 1% of purchased equip cost (B) 5,558

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific

Buildings, as required Building extention to for additional grate sections

Installation Total 30% 177,858

Total Direct Capital Cost 733,663

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 55,581

Construction, field exp. 5% of purchased equip cost (B) 27,790

Construction fee 10% of purchased equip cost (B) 55,581

Startup 2% of purchased equip cost (B) 11,116

Tests 1% of purchased equip cost (B) 5,558

Contingencies 3% of purchased equip cost (B) 16,674

Total Indirect Capital Costs 31% 172,300

Total Capital Investment (TCI) 905,962

Replacement Parts Cost & Installation Labor 0 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 905,962

Total Annualized Capital Costs 85,516

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 446 kW-hr, 8000 hr/yr, 90.0% of capacity 164,279

 Natural Gas (Fuel) NA - 

 Water 0.22 $/Mgal, 8.0 gpm, 8000 hr/yr, 90.0% of capacity 845

 Compressed Air 0.27 $/Mscf, 61.2 scfm, 8000 hr/yr, 90.0% of capacity 7,937

 Reagent #1(Anhydrous Ammonia) NA - 

 Reagent #2 (Urea 50% Solution) 0.09 $/Lb, 765.5 lb/hr, 8000 hr/yr, 50 wt% Urea Soln. 477,350

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 682,286

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 9,060

Insurance (1% total capital costs) 1% of total capital costs (TCI) 9,060

Administration (2% total capital costs) 2% of total capital costs (TCI) 18,119

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 140,880

Total Annual Cost (Annualized Capital Cost + Operating Cost) 823,166

Pollutant Removed (tons/yr) 948

Cost per ton of NOx Removed 868

Notes & Assumptions

1 Equipment cost estimated using 0.6 power factor in conjunction with SNCR cost estimate from Wheelabrator dated 2001. 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover urea piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Equipment cost includes instrumentation. Reduced instrumentation factor from 10% to 1% to account for tie-ins to plant control system

6

7 Make sure bed temp > 610 Deg F to min sulfate formation

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SNCR (175) Page 20 of 44
MPCA BART Analysis 2003

Table I-9: Selective Non-Catalytic Reduction - Grate/Kiln Induration - NOx (175-ppm) (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340,909 scfm

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 446.4 kW-hr 3,571,284 164,279 $/kW-hr, 446 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 8 gpm 3,840 845 $/Mgal, 8.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 61.24189 scfm 29,396,108 7,937 $/Mscf, 61.2 scfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 765.5 lb/hr 5,615,881 477,350 $/Lb, 765.5 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 175.000 ppm, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/2-yr period 0 0 $/Ton, 175.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

175 ppm 300,000 dscfm NA 1,355

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

70% 406.47 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 948

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 377,730 5 0.55 0.9 446.4 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Blower 0 5 0.55 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.20 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 446.4

Ammonia 338.7 lb/hr NOx 0.370 lb NH3/lb NOx 128.8 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 338.7 lb/hr NOx 2.260 lb Urea Sol'n/lb NOx 765.5 lb/hr Urea Sol'n per vendor quote

Comp Air 0.08 scfm per lb/hr Urea 61.2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SNCR (175) Page 21 of 44
MPCA BART Analysis 2003

Table I-10: Pre Heat Low NOx Burner - Straight Grate and Grate/Kiln Induration

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 142,857

Instrumentation 10% of control device cost (A) 14,286

MN Sales Taxes 3.0% of control device cost (A) 4,286

Freight 5% of control device cost (A) 7,143

Auxiliary equipment (not included in CD cost) - of control device cost (A) - See Notes 0

Purchased Equipment Total (B) 18% 168,571

Installation

Foundations & supports 4% of purchased equip cost (B) 6,743

Handling, erection 50% of purchased equip cost (B) 84,286

Electrical 8% of purchased equip cost (B) 13,486

Piping 1% of purchased equip cost (B) 1,686

Insulation 7% of purchased equip cost (B) 11,800

Painting 4% of purchased equip cost (B) 6,743

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 74% 124,743

Total Direct Capital Cost 293,314

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 16,857

Construction, field exp. 20% of purchased equip cost (B) 33,714

Construction fee 10% of purchased equip cost (B) 16,857

Startup 1% of purchased equip cost (B) 1,686

Tests 1% of purchased equip cost (B) 1,686

Contingencies 3% of purchased equip cost (B) 5,057

Total Indirect Capital Costs 45% 75,857

Total Capital Investment (TCI) 369,171

Replacement Parts Cost & Installation Labor 0 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 369,171

Total Annualized Capital Costs 34,847

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 50,000

Supervisor 15% of oper labor costs 7,500

Maintenance Labor 17.50 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 17,500

Maintenance Materials 100% of maint labor costs 17,500

Utilities, Reagents, Waste Management & Replacements

 Electricity NA - 

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Caustic) NA - 

 Reagent #2 NA - 

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 92,500

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 55,500

Property tax (1% total capital costs) 1% of total capital costs (TCI) 3,692

Insurance (1% total capital costs) 1% of total capital costs (TCI) 3,692

Administration (2% total capital costs) 2% of total capital costs (TCI) 7,383

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 105,114

Total Annual Cost (Annualized Capital Cost + Operating Cost) 197,614

Pollutant Removed (tons/yr)B 19

Cost per ton of NOx Removed 10,456

Notes & Assumptions

1 1 At present, cost estimate is assumed to be 33% less than the cost of the Ultra Low NOx Burner bid by JZink, 2003.

2

3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Pre Heat Low NOx Page 22 of 44
MPCA BART Analysis 2003

Table I-10: Pre Heat Low NOx Burner - Straight Grate and Grate/Kiln Induration (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 150,000 dscfm 170,455 scfm

135 Temp Deg F

12% % Moisture

188,865 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization rate: 90%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 2 hr/8 hr shift 2,000 50,000 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 1 hr/8 hr shift 1,000 17,500 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 0.0 kW-hr 0 0 $/kW-hr, 0 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0 Mscf 100 Mscfm 48,000 0 $/Mscf, 100.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, Ammonia

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 0 Ton 0.857 ton/hr 6,857 0 $/Ton, 0.140 lb/mmbtu, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.140 lb/mmbtu, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.14 lb/mmbtu 150 mmbtu/hr NA 76

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

25% 56.70

Emission Reduction T/yr 19

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 0 5 0.55 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 3.37

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Pre Heat Low NOx Page 23 of 44
MPCA BART Analysis 2003

Table I-11: Pre Heat Ultra Low NOx Burner - Straight Grate and Grate/Kiln Induration

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 190,000

Instrumentation 10% of control device cost (A) 19,000

MN Sales Taxes 3.0% of control device cost (A) 5,700

Freight 5% of control device cost (A) 9,500

Auxiliary equipment (not included in CD cost) - of control device cost (A) 55,000

Purchased Equipment Total (B) 18% 279,200

Installation

Foundations & supports 4% of purchased equip cost (B) 11,168

Handling, erection 50% of purchased equip cost (B) 139,600

Electrical 8% of purchased equip cost (B) 22,336

Piping 1% of purchased equip cost (B) 2,792

Insulation 7% of purchased equip cost (B) 19,544

Painting 4% of purchased equip cost (B) 11,168

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 74% 206,608

Total Direct Capital Cost 485,808

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 27,920

Construction, field exp. 20% of purchased equip cost (B) 55,840

Construction fee 10% of purchased equip cost (B) 27,920

Startup 1% of purchased equip cost (B) 2,792

Tests 1% of purchased equip cost (B) 2,792

Contingencies 3% of purchased equip cost (B) 8,376

Total Indirect Capital Costs 45% 125,640

Total Capital Investment (TCI) 611,448

Replacement Parts Cost & Installation Labor 0 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 611,448

Total Annualized Capital Costs 57,716

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 50,000

Supervisor 15% of oper labor costs 7,500

Maintenance Labor 17.50 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 17,500

Maintenance Materials 100% of maint labor costs 17,500

Utilities, Reagents, Waste Management & Replacements

 Electricity NA - 

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air 0.25 $/Mscf, 100.0 Mscfm, 8000 hr/yr, 90.0% of capacity 12,000

 Reagent #1(Caustic) NA - 

 Reagent #2 NA - 

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 104,500

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 55,500

Property tax (1% total capital costs) 1% of total capital costs (TCI) 6,114

Insurance (1% total capital costs) 1% of total capital costs (TCI) 6,114

Administration (2% total capital costs) 2% of total capital costs (TCI) 12,229

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 137,674

Total Annual Cost (Annualized Capital Cost + Operating Cost) 242,174

Pollutant Removed (tons/yr)B 37.8

Cost per ton of NOx Removed 6,407

Notes & Assumptions

1 1 Equipment cost estimate provided by JZink. Additional cost of $55000 required for FD fan and auxillary equipment.

2 Assumed control efficiency is based on 3% excess air. Actual operating conditions are at 300-400% excess air.

3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Pre Heat ULNB Page 24 of 44
MPCA BART Analysis 2003

Table I-11: Pre Heat Ultra Low NOx Burner - Straight Grate and Grate/Kiln Induration (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft

3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 150,000 dscfm 170,455 scfm

135 Temp Deg F

12% % Moisture

188,865 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization rate: 90%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 2 hr/8 hr shift 2,000 50,000 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 1 hr/8 hr shift 1,000 17,500 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 0.0 kW-hr 0 0 $/kW-hr, 0 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 100 Mscfm 48,000 12,000 $/Mscf, 100.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, Ammonia

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 0 Ton 0.857 ton/hr 6,857 0 $/Ton, 0.140 lb/mmbtu, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.140 lb/mmbtu, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.14 lb/mmbtu 150 mmbtu/hr NA 76

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

50% 37.80

Emission Reduction T/yr 37.80

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 0 5 0.55 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 3.37

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Pre Heat ULNB Page 25 of 44
MPCA BART Analysis 2003

Table I-12: Selective Catalytic Reduction - Straight Grate Induration with Duct Burner - NOx

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 1,210,590

Instrumentation 10% of control device cost (A) 121,059

MN Sales Taxes 6.5% of control device cost (A) 78,688

Freight 5% of control device cost (A) 60,530

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 1,470,867

Installation

Foundations & supports 8% of purchased equip cost (B) 117,669

Handling, erection 14% of purchased equip cost (B) 205,921

Electrical 4% of purchased equip cost (B) 58,835

Piping 4% of purchased equip cost (B) 58,835

Insulation 1% of purchased equip cost (B) 14,709

Painting 1% of purchased equip cost (B) 14,709

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 470,677

Total Direct Capital Cost 1,941,544

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 147,087

Construction, field exp. 5% of purchased equip cost (B) 73,543

Construction fee 10% of purchased equip cost (B) 147,087

Startup 2% of purchased equip cost (B) 29,417

Tests 1% of purchased equip cost (B) 14,709

Contingencies 3% of purchased equip cost (B) 44,126

Total Indirect Capital Costs 31% 455,969

Total Capital Investment (TCI) 2,397,513

Replacement Parts Cost & Installation Labor 506,448 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 1,891,065

Total Annualized Capital Costs 178,503

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 509 kW-hr, 8000 hr/yr, 90.0% of capacity 187,277

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Anhydrous Ammonia) 405.00 $/Ton, 32.1 lb/hr, 8000 hr/yr, Ammonia 47,755

 Reagent #2 (Urea 50% Solution) NA - 

 Solid Waste Disposal 25.00 $/Ton, 25.4 ton/yr 634

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst 156.72 $/ft3, 2,898.2 ft3, 2, 8000 hr/yr, 90.0% of capacity 280,112

 Replacement Parts NA - 

Total Annual Direct Operating Costs 547,653

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 23,975

Insurance (1% total capital costs) 1% of total capital costs (TCI) 23,975

Administration (2% total capital costs) 2% of total capital costs (TCI) 47,950

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 293,529

Total Annual Cost (Annualized Capital Cost + Operating Cost) (SCR) 841,182

Total Annual Cost (Annualized Capital Cost + Operating Cost) (Burner) 1,781,185

Total Annual Cost (Annualized Capital Cost + Operating Cost) (SCR + Burner) 2,622,367

Pollutant Removed (tons/yr) 279

Cost per ton of NOx Removed 9,408

Notes & Assumptions

1 Equipment cost estimates obtained from cost curve created from Born Environmental SCR cost estimate dated, 2001 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover ammonia piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Make sure bed temp > 610 Deg F to min sulfate formation

6 Specify large passage size for catalyst bed. Include soot blowing mechanism & ID any cleaning practices needed

7 Check for potential of any issue with ammonium bisulfate plugging downsteam equipment.

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate - SCR + Duct Page 26 of 44
MPCA BART Analysis 2003

Table I-12: Selective Catalytic Reduction - Straight Grate Induration with Duct Burner - NOx (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years Catalyst Disposal Amount in Tons/yr at 35 lb/ft3

CRF 0.5531 Amount Yrs Service T/yr Waste

Catalyst cost per unit 156.72 $/ft3 50.7 2 25.4

Amount Required 2898.2 ft3

Catalyst Cost 506,448 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 506,448

Annualized Cost 280,112

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 506,448

Design Flow 150,000 dscfm scfm 170,455

135 Temp Deg F

12% % Moisture

188,865 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 508.9 kW-hr 4,071,246 187,277 $/kW-hr, 509 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 32.1 lb/hr 235,828 47,755 $/Ton, 32.1 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 0.0 lb/hr 0 0 $/Lb, 0.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 25.4 ton/yr 25 634 $/Ton, 25.4 ton/yr

Haz W Disp 273 Ton 0.000 ton/2-yr period 0.00 0 $/Ton, 80.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 156.72 ft3 2898.2 ft3 2 280,112 $/ft3, 2,898.2 ft3, 2, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 0 $/$/bag, 0.0 bags, 2, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

80.0 ppm 150,000 dscfm NA 310

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

90% 30.97 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 279

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 188,865 11.4 0.55 0.9 508.9 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.05 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 508.9

Ammonia 77.4 lb/hr NOx 0.370 lb NH3/lb NOx 32.1 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 77.4 lb/hr NOx 1.317 lb Urea Sol'n/lb NOx 114.5 lb/hr Urea Sol'n; inlcudes 12.5 lb/hr for NH3 slip

Estimating amount of catalyst required 

Vol. #1 5513 ft3

Flow #1 359256 acfm

Flow #2 188,865 

Vol #2 2898.2 ft3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate - SCR + Duct Page 27 of 44
MPCA BART Analysis 2003

Table I-12.1: Selective Catalytic Reduction - Duct Burner for Straight Grate Induration

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 676,513

Instrumentation 10% of control device cost (A) 67,651

MN Sales Taxes 6.5% of control device cost (A) 43,973

Freight 5% of control device cost (A) 33,826

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 821,963

Installation

Foundations & supports 8% of purchased equip cost (B) 65,757

Handling, erection 14% of purchased equip cost (B) 115,075

Electrical 4% of purchased equip cost (B) 32,879

Piping 2% of purchased equip cost (B) 16,439

Insulation 1% of purchased equip cost (B) 8,220

Painting 1% of purchased equip cost (B) 8,220

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 246,589

Total Direct Capital Cost 1,068,552

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 82,196

Construction, field exp. 5% of purchased equip cost (B) 41,098

Construction fee 10% of purchased equip cost (B) 82,196

Startup 2% of purchased equip cost (B) 16,439

Tests 1% of purchased equip cost (B) 8,220

Contingencies 3% of purchased equip cost (B) 24,659

Total Indirect Capital Costs 31% 254,809

Total Capital Investment (TCI) 1,323,360

Replacement Parts Cost & Installation Labor 0 Capital Recovery Cost for Control System 1,323,360

Total Annualized Capital Costs 124,916

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.06 $/kW-hr, 223 kW-hr, 8000 hr/yr, 90.0% of capacity 105,352

 Natural Gas (Fuel) 3.30 $/Mft3, 913 scfm, 8000 hr/yr, 90.0% of capacity 1,446,982

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Caustic) NA - 

 Reagent #2 NA - 

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 1,584,210

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,234

Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,234

Administration (2% total capital costs) 2% of total capital costs (TCI) 26,467

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 196,975

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,781,185

Pollutant Removed (tons/yr)B -

Cost per ton of PM Removed -

Notes & Assumptions

1 1

2

3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate Duct Burner Page 28 of 44
MPCA BART Analysis 2003

Table I-12.1: Selective Catalytic Reduction - Duct Burner for Straight Grate Induration (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 150,000 dscfm 170,455 scfm

135 Temp Deg F

12% % Moisture

188,865 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% NA 1875 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.059 kW-hr 223.2 kW-hr 1,785,632 105,352 $/kW-hr, 223 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 3.3 Mft3 913 scfm 438,479 1,446,982 $/Mft3, 913 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, Ammonia

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.000 , 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.000 , 8000 hr/yr 

WW Treat 3.8 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Emis Rate

Factor Measure Rate Measure T/yr Comments/Notes

1000

Controlled Emission Rate 

Perf Unit of Flow Unit of Emis Rate

Guarantee Measure Rate Measure T/yr Comments/Notes

500

Emission Reduction T/yr 500

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 188,865 5 0.55 0.9 223.2 OAQPS Cost Cont Manual 5th ed - Eq 3.37

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate Duct Burner Page 29 of 44
MPCA BART Analysis 2003

Table I-12.1: Selective Catalytic Reduction - Duct Burner for Straight Grate Induration (Continued)

Duct Burner Cost Estimate

Auxiliary Fuel Use Equation 3.19 Input Numbers

Twi 150 Deg F - Temperature of waste gas into heat recovery Calculated Numbers

Tfi 750 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 570 Deg F - Temperature of waste gas out of heat recovery

Tfo 330 Deg F - Temperature of flue gas into of heat recovery 

Flow Calculator

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane) Design Flow 150,000 dscfm 170,455 scfm

-hwg 0 Btu/lb Heat of combustion waste gas 135 Temp Deg F

Cp wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas (air) 12% % Moisture

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F 188,865 acfm

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F

Qwg 170,455 scfm - Flow of waste gas 

Qaf 913 scfm - Flow of auxiliary fuel

Year 2003 Inflation Rate 3.0%

Cost Calculations 171,368 scfm Flue Gas Cost in 1988 $'s $434,228

Current Cost @ 3% inflation $676,513

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls St Grate Duct Burner Page 30 of 44
MPCA BART Analysis 2003

Table I-13: Selective Catalytic Reduction - Grate/Kiln Induration with Duct Burner - NOx (50-ppm)

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 2,111,299

Instrumentation 10% of control device cost (A) 211,130

MN Sales Taxes 6.5% of control device cost (A) 137,234

Freight 5% of control device cost (A) 105,565

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 2,565,228

Installation

Foundations & supports 8% of purchased equip cost (B) 205,218

Handling, erection 14% of purchased equip cost (B) 359,132

Electrical 4% of purchased equip cost (B) 102,609

Piping 4% of purchased equip cost (B) 102,609

Insulation 1% of purchased equip cost (B) 25,652

Painting 1% of purchased equip cost (B) 25,652

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 820,873

Total Direct Capital Cost 3,386,101

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 256,523

Construction, field exp. 5% of purchased equip cost (B) 128,261

Construction fee 10% of purchased equip cost (B) 256,523

Startup 2% of purchased equip cost (B) 51,305

Tests 1% of purchased equip cost (B) 25,652

Contingencies 3% of purchased equip cost (B) 76,957

Total Indirect Capital Costs 31% 795,221

Total Capital Investment (TCI) 4,181,322

Replacement Parts Cost & Installation Labor 1,012,895 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 3,168,427

Total Annualized Capital Costs 299,077

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity 374,554

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Anhydrous Ammonia) 405.00 $/Ton, 39.3 lb/hr, 8000 hr/yr, Ammonia 58,394

 Reagent #2 (Urea 50% Solution) NA - 

 Solid Waste Disposal 25.00 $/Ton, 50.7 ton/yr 1,268

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst 156.72 $/ft3, 5,796.5 ft3, 2, 8000 hr/yr, 90.0% of capacity 560,224

 Replacement Parts NA - 

Total Annual Direct Operating Costs 1,026,315

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 41,813

Insurance (1% total capital costs) 1% of total capital costs (TCI) 41,813

Administration (2% total capital costs) 2% of total capital costs (TCI) 83,626

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 485,455

Total Annual Cost (Annualized Capital Cost + Operating Cost) (SCR) 1,511,770

Total Annual Cost (Annualized Capital Cost + Operating Cost) (Burner) 3,367,170

Total Annual Cost (Annualized Capital Cost + Operating Cost) (SCR + Burner) 4,878,940

Pollutant Removed (tons/yr) 348

Cost per ton of NOx Removed 14,004

Notes & Assumptions

1 Equipment cost estimates obtained from cost curve created from Born Environmental SCR cost estimate dated, 2001 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover ammonia piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop alreading part of plant design

5 Make sure bed temp > 610 Deg F to min sulfate formation

6 Specify large passage size for catalyst bed. Include soot blowing mechanism & ID any cleaning practices needed

7 Check for potential of any issue with ammonium bisulfate plugging downsteam equipment.

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR + Duct (50) Page 31 of 44
MPCA BART Analysis 2003

Table I-13: Selective Catalytic Reduction - Grate/Kiln Induration with Duct Burner - NOx (50-ppm) (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years Catalyst Disposal Amount in Tons/yr at 35 lb/ft3

CRF 0.5531 Amount Yrs Service T/yr Waste

Catalyst cost per unit 156.72 $/ft3 101.4 2 50.7

Amount Required 5796.5 ft3

Catalyst Cost 1,012,895 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 1,012,895

Annualized Cost 560,224

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 1,012,895

Design Flow 300,000 dscfm scfm 340,909

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1017.8 kW-hr 8,142,488 374,554 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 39.3 lb/hr 288,366 58,394 $/Ton, 39.3 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 0.0 lb/hr 0 0 $/Lb, 0.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 50.7 ton/yr 51 1,268 $/Ton, 50.7 ton/yr

Haz W Disp 273 Ton 0.000 ton/2-yr period 0.00 0 $/Ton, 50.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 156.72 ft3 5796.5 ft3 2 560,224 $/ft3, 5,796.5 ft3, 2, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 0 $/$/bag, 0.0 bags, 2, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

50.0 ppm 300,000 dscfm NA 387

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

90% 38.71 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 348

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 377,730 11.4 0.55 0.9 1017.8 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.06 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 1017.8

Ammonia 96.8 lb/hr NOx 0.370 lb NH3/lb NOx 39.3 lb/hr NH3; inlcudes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 96.8 lb/hr NOx 1.317 lb Urea Sol'n/lb NOx 140.0 lb/hr Urea Sol'n; inlcudes 12.5 lb/hr for NH3 slip

Estimating amount of catalyst required 

Vol. #1 5513 ft3

Flow #1 359256 acfm

Flow #2 377,730 

Vol #2 5796.5 ft3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR + Duct (50) Page 32 of 44
MPCA BART Analysis 2003

Table I-13.1: Selective Catalytic Reduction - Duct Burner for Grate/Kiln Induration - NOx

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 804,514

Instrumentation 10% of control device cost (A) 80,451

MN Sales Taxes 6.5% of control device cost (A) 52,293

Freight 5% of control device cost (A) 40,226

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 977,484

Installation

Foundations & supports 8% of purchased equip cost (B) 78,199

Handling, erection 14% of purchased equip cost (B) 136,848

Electrical 4% of purchased equip cost (B) 39,099

Piping 2% of purchased equip cost (B) 19,550

Insulation 1% of purchased equip cost (B) 9,775

Painting 1% of purchased equip cost (B) 9,775

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 293,245

Total Direct Capital Cost 1,270,729

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 97,748

Construction, field exp. 5% of purchased equip cost (B) 48,874

Construction fee 10% of purchased equip cost (B) 97,748

Startup 2% of purchased equip cost (B) 19,550

Tests 1% of purchased equip cost (B) 9,775

Contingencies 3% of purchased equip cost (B) 29,325

Total Indirect Capital Costs 31% 303,020

Total Capital Investment (TCI) 1,573,749

Replacement Parts Cost & Installation Labor 0 Capital Recovery Cost for Control System 1,573,749

Total Annualized Capital Costs 148,551

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.06 $/kW-hr, 446 kW-hr, 8000 hr/yr, 90.0% of capacity 210,705

 Natural Gas (Fuel) 3.30 $/Mft3, 1,827 scfm, 8000 hr/yr, 90.0% of capacity 2,893,964

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Caustic) NA - 

 Reagent #2 NA - 

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 3,136,544

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 15,737

Insurance (1% total capital costs) 1% of total capital costs (TCI) 15,737

Administration (2% total capital costs) 2% of total capital costs (TCI) 31,475

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 230,626

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,367,170

Pollutant Removed (tons/yr)B -

Cost per ton of PM Removed -

Notes & Assumptions

1 1

2

3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate,Kiln Duct Burner (50) Page 33 of 44
MPCA BART Analysis 2003

Table I-13.1: Selective Catalytic Reduction - Duct Burner for Grate/Kiln Induration - NOx (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340,909 scfm

135 Temp Deg F

12% % Moisture

 ac 377,730 fm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% NA 1875 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.059 kW-hr 446.4 kW-hr 3,571,264 210,705 $/kW-hr, 446 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 3.3 Mft3 1,827 scfm 876,959 2,893,964 $/Mft3, 1,827 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, Ammonia

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.000 , 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.000 , 8000 hr/yr 

WW Treat 3.8 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Emis Rate

Factor Measure Rate Measure T/yr Comments/Notes

1000

Controlled Emission Rate 

Perf Unit of Flow Unit of Emis Rate

Guarantee Measure Rate Measure T/yr Comments/Notes

500

Emission Reduction T/yr 500

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 377,730 5 0.55 0.9 446.4 OAQPS Cost Cont Manual 5th ed - Eq 3.37

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate,Kiln Duct Burner (50) Page 34 of 44
MPCA BART Analysis 2003

Table I-13.1: Selective Catalytic Reduction - Duct Burner for Grate/Kiln Induration - NOx (Continued)

Duct Burner Cost Estimate

Auxiliary Fuel Use Equation 3.19 Input Numbers

Twi 150 Deg F - Temperature of waste gas into heat recovery Calculated Numbers

Tfi 750 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 570 Deg F - Temperature of waste gas out of heat recovery

Tfo 330 Deg F - Temperature of flue gas into of heat recovery 

Flow Calculator

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane) Design Flow 300,000 dscfm 340,909 scfm

-hwg 0 Btu/lb Heat of combustion waste gas 135 Temp Deg F

Cp wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas (air) 12% % Moisture

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F 377,730 acfm

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F

Qwg 340,909 scfm - Flow of waste gas 

Qaf 1,827 scfm - Flow of auxiliary fuel

Year 2003 Inflation Rate 3.0%

Cost Calculations 342,736 scfm Flue Gas Cost in 1988 $'s $516,387

Current Cost @ 3% inflation $804,514

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate,Kiln Duct Burner (50) Page 35 of 44
MPCA BART Analysis 2003

Table I-14: Selective Catalytic Reduction - Grate/Kiln Induration with Duct Burner - NOx (175-ppm)

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 2,111,299

Instrumentation 10% of control device cost (A) 211,130

MN Sales Taxes 6.5% of control device cost (A) 137,234

Freight 5% of control device cost (A) 105,565

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 2,565,228

Installation

Foundations & supports 8% of purchased equip cost (B) 205,218

Handling, erection 14% of purchased equip cost (B) 359,132

Electrical 4% of purchased equip cost (B) 102,609

Piping 4% of purchased equip cost (B) 102,609

Insulation 1% of purchased equip cost (B) 25,652

Painting 1% of purchased equip cost (B) 25,652

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 820,873

Total Direct Capital Cost 3,386,101

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 256,523

Construction, field exp. 5% of purchased equip cost (B) 128,261

Construction fee 10% of purchased equip cost (B) 256,523

Startup 2% of purchased equip cost (B) 51,305

Tests 1% of purchased equip cost (B) 25,652

Contingencies 3% of purchased equip cost (B) 76,957

Total Indirect Capital Costs 31% 795,221

Total Capital Investment (TCI) 4,181,322

Replacement Parts Cost & Installation Labor 1,012,895 Capital Recovery Costs, Equipment Life 20 years, Interest Rate, 7% 3,168,427

Total Annualized Capital Costs 299,077

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.05 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity 374,555

 Natural Gas (Fuel) NA - 

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Anhydrous Ammonia) 405.00 $/Ton, 128.8 lb/hr, 8000 hr/yr, Ammonia 191,381

 Reagent #2 (Urea 50% Solution) NA - 

 Solid Waste Disposal 25.00 $/Ton, 50.7 ton/yr 1,268

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst 156.72 $/ft3, 5,796.5 ft3, 2, 8000 hr/yr, 90.0% of capacity 560,224

 Replacement Parts NA - 

Total Annual Direct Operating Costs 1,159,303

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 41,813

Insurance (1% total capital costs) 1% of total capital costs (TCI) 41,813

Administration (2% total capital costs) 2% of total capital costs (TCI) 83,626

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 485,455

Total Annual Cost (Annualized Capital Cost + Operating Cost) (SCR) 1,644,758

Total Annual Cost (Annualized Capital Cost + Operating Cost) (Burner) 3,367,170

Total Annual Cost (Annualized Capital Cost + Operating Cost) (SCR + Burner) 5,011,928

Pollutant Removed (tons/yr) 1,219

Cost per ton of NOx Removed 4,110

Notes & Assumptions

1 Equipment cost estimates obtained from cost curve created from Born Environmental SCR cost estimate dated, 2001 

2 Used EPA guideline for catalytic oxidizers for cost analysis. 

3 Increased factor for piping from 2% to 4% to cover ammonia piping. This is consistent with Steel Dynamics Analysis

4 Air blower power costs for catalyst bed pressure drop; ductwork pressure drop already part of plant design

5 Make sure bed temp > 610 Deg F to min sulfate formation

6 Specify large passage size for catalyst bed. Include soot blowing mechanism & ID any cleaning practices needed

7 Check for potential of any issue with ammonium bisulfate plugging downsteam equipment.

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR + Duct (175) Page 36 of 44
MPCA BART Analysis 2003

Table I-14: Selective Catalytic Reduction - Grate/Kiln Induration with Duct Burner - NOx (175-ppm) (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years Catalyst Disposal Amount in Tons/yr at 35 lb/ft3

CRF 0.5531 Amount Yrs Service T/yr Waste

Catalyst cost per unit 156.72 $/ft3 101.4 2 50.7

Amount Required 5796.5 ft3

Catalyst Cost 1,012,895 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 1,012,895

Annualized Cost 560,224

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 1,012,895

Design Flow 300,000 dscfm scfm 340,909

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25.00 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1017.8 kW-hr 8,142,502 374,555 $/kW-hr, 1,018 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Anhydrous Ammonia) 405 Ton 128.8 lb/hr 945,090 191,381 $/Ton, 128.8 lb/hr, 8000 hr/yr, Ammonia

Reagent #2 (Urea 50% Solution) 0.085 Lb 0.0 lb/hr 0 0 $/Lb, 0.0 lb/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 50.7 ton/yr 51 1,268 $/Ton, 50.7 ton/yr

Haz W Disp 273 Ton 0.000 ton/2-yr period 0.00 0 $/Ton, 175.000 ppm, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 156.72 ft3 5796.5 ft3 2 560,224 $/ft3, 5,796.5 ft3, 2, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 0 $/$/bag, 0.0 bags, 2, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Control Eff. Emis Rate

Factor Measure Hrs Capacity % T/yr Comments/Notes

175.0 ppm 300,000 dscfm NA 1,355

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

90% 135.49 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 1,219

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 377,730 11.4 0.55 0.9 1017.8 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Reagent Pump 0.20 50 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Total Electricity 1017.8

Ammonia 338.7 lb/hr NOx 0.370 lb NH3/lb NOx 128.8 lb/hr NH3; includes 3.5 lb/hr for NH3 slip

Urea 50% Sol'n 338.7 lb/hr NOx 1.317 lb Urea Sol'n/lb NOx 458.6 lb/hr Urea Sol'n; includes 12.5 lb/hr for NH3 slip

Estimating amount of catalyst required 

Vol. #1 5513 ft3

Flow #1 359256 acfm

Flow #2 377,730 

Vol #2 5796.5 ft3

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate, Kiln - SCR + Duct (175) Page 37 of 44
MPCA BART Analysis 2003

Table I-14.1: Selective Catalytic Reduction - Duct Burner for Grate/Kiln Induration - NOx

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 804,514

Instrumentation 10% of control device cost (A) 80,451

MN Sales Taxes 6.5% of control device cost (A) 52,293

Freight 5% of control device cost (A) 40,226

Auxiliary equipment (not included in CD cost) 0% of control device cost (A) 0

Purchased Equipment Total (B) 18% 977,484

Installation

Foundations & supports 8% of purchased equip cost (B) 78,199

Handling, erection 14% of purchased equip cost (B) 136,848

Electrical 4% of purchased equip cost (B) 39,099

Piping 2% of purchased equip cost (B) 19,550

Insulation 1% of purchased equip cost (B) 9,775

Painting 1% of purchased equip cost (B) 9,775

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 30% 293,245

Total Direct Capital Cost 1,270,729

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 97,748

Construction, field exp. 5% of purchased equip cost (B) 48,874

Construction fee 10% of purchased equip cost (B) 97,748

Startup 2% of purchased equip cost (B) 19,550

Tests 1% of purchased equip cost (B) 9,775

Contingencies 3% of purchased equip cost (B) 29,325

Total Indirect Capital Costs 31% 303,020

Total Capital Investment (TCI) 1,573,749

Replacement Parts Cost & Installation Labor 0 Capital Recovery Cost for Control System 1,573,749

Total Annualized Capital Costs 148,551

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.06 $/kW-hr, 446 kW-hr, 8000 hr/yr, 90.0% of capacity 210,705

 Natural Gas (Fuel) 3.30 $/Mft3, 1,827 scfm, 8000 hr/yr, 90.0% of capacity 2,893,964

 Water NA - 

 Compressed Air NA - 

 Reagent #1(Caustic) NA - 

 Reagent #2 NA - 

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment NA - 

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 3,136,544

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 15,737

Insurance (1% total capital costs) 1% of total capital costs (TCI) 15,737

Administration (2% total capital costs) 2% of total capital costs (TCI) 31,475

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 230,626

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,367,170

Pollutant Removed (tons/yr) B -

Cost per ton of PM Removed -

Notes & Assumptions

1

2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate,Kiln Duct Burner (175) Page 38 of 44
MPCA BART Analysis 2003

Table I-14.1: Selective Catalytic Reduction - Duct Burner for Grate/Kiln Induration - NOx (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340,909 scfm

135 Temp Deg F

12% % Moisture

 ac 377,730 fm

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% NA 1875 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.059 kW-hr 446.4 kW-hr 3,571,264 210,705 $/kW-hr, 446 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 3.3 Mft

3 1,827 scfm 876,959 2,893,964 $/Mft3, 1,827 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, Ammonia

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 50 wt% Urea Soln.

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.000 , 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.000 , 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Emis Rate

Factor Measure Rate Measure T/yr Comments/Notes

1000

Controlled Emission Rate 

Perf Unit of Flow Unit of Emis Rate

Guarantee Measure Rate Measure T/yr Comments/Notes

500

Emission Reduction T/yr 500

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 377,730 5 0.55 0.9 446.4 OAQPS Cost Cont Manual 5th ed - Eq 3.37

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate,Kiln Duct Burner (175) Page 39 of 44
MPCA BART Analysis 2003

Table I-14.1: Selective Catalytic Reduction - Duct Burner for Grate/Kiln Induration - NOx (Continued)

Duct Burner Cost Estimate

Auxiliary Fuel Use Equation 3.19 Input Numbers

Twi 150 Deg F - Temperature of waste gas into heat recovery Calculated Numbers

Tfi 750 Deg F - Temperature of Flue gas into of heat recovery

Tref 77 Deg F - Reference temperature for fuel combustion calculations

FER 70% Factional Heat Recovery % Heat recovery section efficiency

Two 570 Deg F - Temperature of waste gas out of heat recovery

Tfo 330 Deg F - Temperature of flue gas into of heat recovery 

Flow Calculator

-hcaf 21502 Btu/lb Heat of combustion auxiliary fuel (methane) Design Flow 300,000 dscfm 340,909 scfm

-hwg 0 Btu/lb Heat of combustion waste gas 135 Temp Deg F

Cp wg 0.255 Btu/lb - Deg F Heat Capacity of waste gas (air) 12% % Moisture

p wg 0.0739 lb/scf - Density of waste gas (air) at 77 Deg F 377,730 acfm

p af 0.0408 lb/scf - Density of auxiliary fuel (methane) at 77 Deg F

Qwg 340,909 scfm - Flow of waste gas 

Qaf 1,827 scfm - Flow of auxiliary fuel

Year 2003 Inflation Rate 3.0%

Cost Calculations 342,736 scfm Flue Gas Cost in 1988 $'s $516,387

Current Cost @ 3% inflation $804,514

Heat Rec % A B

0 10,294 0.2355 Exponents per equation 3.24

0.3 13,149 0.2609 Exponents per equation 3.25

0.5 17,056 0.2502 Exponents per equation 3.26

0.7 21,342 0.2500 Exponents per equation 3.27

Reference: OAQPS Control Cost Manual 5th Ed Feb 1996 - Chapter 3 Thermal & Catalytic Incinerators

 (EPA 453/B-96-001)

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls Grate,Kiln Duct Burner (175) Page 40 of 44
MPCA BART Analysis 2003

Table I-15: LTO Scrubber - Grate/Kiln Induration - NOx (50-ppm) 

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 9,464,103

Instrumentation 1% of control device cost (A) 94,641

MN Sales Taxes 6.5% of control device cost (A) 615,167

Freight 5% of control device cost (A) 473,205

Auxiliary equipment (not included in CD cost) 5.0% of control device cost (A) 473,205

Purchased Equipment Total (B) 18% 11,120,321

Installation

Foundations & supports 12% of purchased equip cost (B) 1,334,439

Handling, erection 40% of purchased equip cost (B) 4,448,128

Electrical 1% of purchased equip cost (B) 111,203

Piping 30% of purchased equip cost (B) 3,336,096

Insulation 1% of purchased equip cost (B) 111,203

Painting 1% of purchased equip cost (B) 111,203

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 85% 9,452,273

Total Direct Capital Cost 20,572,594

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 1,112,032

Construction, field exp. 10% of purchased equip cost (B) 1,112,032

Construction fee 10% of purchased equip cost (B) 1,112,032

Startup 1% of purchased equip cost (B) 111,203

Tests 1% of purchased equip cost (B) 111,203

Contingencies 3% of purchased equip cost (B) 333,610

Total Indirect Capital Costs 35% 3,892,112

Total Capital Investment (TCI) + Technology Fee of $1,012,000 25,476,706 Replacement Parts Cost & Installation Labor 0 Capital Recovery Cost for Control System 25,476,706

Total Annualized Capital Costs 2,404,821

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.0460 $/kW-hr, 1,052.0 kW-hr, 8000 hr/yr, 90.0% of capacity 387,136

 Natural Gas (Fuel) NA - 

 Water 0.22 $/Mgal, 180.0 gpm, 8000 hr/yr, 90.0% of capacity 19,008

 Compressed Air NA - 

 Reagent #1(Oxygen) 1.2 $/Mscf, 1.9 mscfh, 8000 hr/yr 16,272

 Reagent #2 NA - 

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment 5.35 $/Mgal, 180.0 gpm, 8000 hr/yr, 90.0% of capacity 462,240

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 916,531

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 254,767

Insurance (1% total capital costs) 1% of total capital costs (TCI) 254,767

Administration (2% total capital costs) 2% of total capital costs (TCI) 509,534

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 3,443,014

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,359,545

Pollutant Removed (tons/yr) 348

Cost per ton of NOx Removed 12,513

Notes & Assumptions

1 Aux equip & supports estimated at 5%. Vendor is more complete than other scrubber bids which had a 15% factor for auxiliary equipment.

2 Make up- water & wastewater blowdown rates = 20% of circulating rate per vendor

3 Equipment cost estimate from vendor dated 7/2/2001 

4 Oxygen use and electric power use for LTO skid provided by vendor

5 Equipment cost includes instrumentation. Reduced instrumentation factor from 10% to 1% to account for tie-ins to plant control system

6 Used biological treatment cost for wastewater to address treatment for nitrates

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls LTO NOx Scrub G-K 50 Page 41 of 44
MPCA BART Analysis 2003

Table I-15: LTO Scrubber - Grate/Kiln Induration - NOx (50-ppm) (Continued)

Capital Recovery Factors

Primary Installation

Interest Rate 7.0%

Equipment Life 20 years Equipment Life per Vendor

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life years

CRF

Catalyst cost per unit $/ft3

Amount Required ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life

CRF

Rep part cost per unit $ each

Amount Required Number

Total Rep Parts Cost Cost adjusted for freight & sales tax

Installation Labor 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1052 kW-hr 8,416,000 387,136 $/kW-hr, 1,052.0 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 180.0 gpm 86,400 19,008 $/Mgal, 180.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Oxygen) 1.2 Mscf 2 mscfh 13,560 16,272 $/Mscf, 1.9 mscfh, 8000 hr/yr

Reagent #2 0 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.0 ton/hr, 50.00 ppm, 8000 hr/yr. 90.0% of capacity

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.0 ton/hr, 50.00 ppm, 8000 hr/yr. 90.0% of capacity

WW Treat 5.35 Mgal 180.0 gpm 86,400 462,240 $/Mgal, 180.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Emis Rate

Factor Measure Hrs Capacity T/yr Comments/Notes

50.0 ppm 300,000 dscfm 387

Controlled Emission Rate 

Perf Unit of Flow Unit of Emis Rate

Guarantee Measure Rate Measure T/yr Comments/Notes

90% Pct Red 39 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 348

Flow acfm P in H2O Blower Eff Motor Eff kW

Blower OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 900 Estimated from Vendor Data (gpm= mscfh gas * 3)

H2O WW Disch 180 Water Makeup Rate/WW Disch = 20% of circulating water rate

LTO Skid Electric Use 1,052 Estimated from Vendor Data

Oxygen Use 1.9 mscfh Estimated from Vendor Data

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls LTO NOx Scrub G-K 50 Page 42 of 44
MPCA BART Analysis 2003

Table I-16: LTO Scrubber - Grate/Kiln Induration - NOx (175-ppm) 

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Control Device (A) 16,464,811

Instrumentation 1% of control device cost (A) 164,648

MN Sales Taxes 6.5% of control device cost (A) 1,070,213

Freight 5% of control device cost (A) 823,241

Auxiliary equipment (not included in CD cost) 5.0% of control device cost (A) 823,241

Purchased Equipment Total (B) 18% 19,346,153

Installation

Foundations & supports 12% of purchased equip cost (B) 2,321,538

Handling, erection 40% of purchased equip cost (B) 7,738,461

Electrical 1% of purchased equip cost (B) 193,462

Piping 30% of purchased equip cost (B) 5,803,846

Insulation 1% of purchased equip cost (B) 193,462

Painting 1% of purchased equip cost (B) 193,462

Expenses not covered by items listed above 0% of purchased equip cost (B) 0

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Installation Total 85% 16,444,230

Total Direct Capital Cost 35,790,383

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 1,934,615

Construction, field exp. 10% of purchased equip cost (B) 1,934,615

Construction fee 10% of purchased equip cost (B) 1,934,615

Startup 1% of purchased equip cost (B) 193,462

Tests 1% of purchased equip cost (B) 193,462

Contingencies 3% of purchased equip cost (B) 580,385

Total Indirect Capital Costs 35% 6,771,154

Total Capital Investment (TCI) + Technology Fee of $1,012,000 43,573,536 Replacement Parts Cost & Installation Labor 0 Capital Recovery Cost for Control System 43,573,536

Total Annualized Capital Costs 4,113,034

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 12,500

Supervisor 15% of oper labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr 8,750

Maintenance Materials 100% of maint labor costs 8,750

Utilities, Reagents, Waste Management & Replacements

 Electricity 0.0460 $/kW-hr, 3,394.0 kW-hr, 8000 hr/yr, 90.0% of capacity 1,248,992

 Natural Gas (Fuel) NA - 

 Water 0.22 $/Mgal, 180.0 gpm, 8000 hr/yr, 90.0% of capacity 19,008

 Compressed Air NA - 

 Reagent #1(Oxygen) 1.2 $/Mscf, 6.6 mscfh, 8000 hr/yr 57,024

 Reagent #2 NA - 

 Solid Waste Disposal NA - 

 Hazardous Waste Disposal NA - 

 Wastewater Treatment 5.35 $/Mgal, 180.0 gpm, 8000 hr/yr, 90.0% of capacity 462,240

 Catalyst NA - 

 Replacement Parts NA - 

Total Annual Direct Operating Costs 1,819,139

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Property tax (1% total capital costs) 1% of total capital costs (TCI) 435,735

Insurance (1% total capital costs) 1% of total capital costs (TCI) 435,735

Administration (2% total capital costs) 2% of total capital costs (TCI) 871,471

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,875,100

Total Annual Cost (Annualized Capital Cost + Operating Cost) 7,694,239

Pollutant Removed (tons/yr) 1,219

Cost per ton of NOx Removed 6,310

Notes & Assumptions

1 Aux equip & supports estimated at 5%. Vendor is more complete than other scrubber bids which had a 15% factor for auxiliary equipment.

2 Make up- water & wastewater blowdown rates = 20% of circulating rate per vendor

3 Equipment cost estimate from vendor dated 7/2/2001 

4 Oxygen use and electric power use for LTO skid provided by vendor

5 Equipment cost includes instrumentation. Reduced instrumentation factor from 10% to 1% to account for tie-ins to plant control system

6 Used biological treatment cost for wastewater to address treatment for nitrates

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls LTO NOx Scrub G-K 175 Page 43 of 44
MPCA BART Analysis 2003

Table I-16: LTO Scrubber - Grate/Kiln Induration - NOx (175-ppm) (Continued) 

Capital Recovery Factors

Primary Installation

Interest Rate 7.0%

Equipment Life 20 years Equipment Life per Vendor

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life years

CRF

Catalyst cost per unit $/ft3

Amount Required ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life

CRF

Rep part cost per unit $ each

Amount Required Number

Total Rep Parts Cost Cost adjusted for freight & sales tax

Installation Labor 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Operating Cost Calculations Utilization Rate 90.0%

Annual hours of operation: 8,000

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 3394 kW-hr 27,152,000 1,248,992 $/kW-hr, 3,394.0 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 180.0 gpm 86,400 19,008 $/Mgal, 180.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Oxygen) 1.2 Mscf 7 mscfh 47,520 57,024 $/Mscf, 6.6 mscfh, 8000 hr/yr

Reagent #2 0 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.0 ton/hr, 175.00 ppm, 8000 hr/yr. 90.0% of capacity

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.0 ton/hr, 175.00 ppm, 8000 hr/yr. 90.0% of capacity

WW Treat 5.35 Mgal 180.0 gpm 86,400 462,240 $/Mgal, 180.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Rate % Max Emis Rate

Factor Measure Hrs Capacity T/yr Comments/Notes

175.0 ppm 300,000 dscfm 1,355

Controlled Emission Rate 

Perf Unit of Flow Unit of Emis Rate

Guarantee Measure Rate Measure T/yr Comments/Notes

90% Pct Red 135 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 1,219

Flow acfm P in H2O Blower Eff Motor Eff kW

Blower OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 900 Estimated from Vendor Data (gpm= mscfh gas * 3)

H2O WW Disch 180 Water Makeup Rate/WW Disch = 20% of circulating water rate

LTO Skid Electric Use 3,394 Estimated from Vendor Data

Oxygen Use 6.6 mscfh Estimated from Vendor Data

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment I.xls LTO NOx Scrub G-K 175 Page 44 of 44
ATTACHMENT J 

Model BART Cost Analysis - Induration Furnace SO2 Emissions 

List of Tables: 

Table J-1: BART Screening Evaluation Summary: Straight Grate Induration - Wet Scrubber and Wet 

Wall ESP 

Table J-2: BART Screening Evaluation Summary: Grate/Kiln Induration - Wet Scrubber and Wet Wall 

ESP 

Table J-3: Wet Wall ESP - Straight Grate Induration - SO2 

Table J-4: Wet Wall ESP - Grate/Kiln Induration - SO2 (20-ppm) 

Table J-5: Wet Wall ESP - Grate/Kiln Induration - SO2 (20-ppm) + PM 

Table J-6: Wet Wall ESP - Grate/Kiln Induration - SO2 (130-ppm) 

Table J-7: Low Efficiency Wet Scrubber - Straight Grate Induration - SO2 

Table J-8: High Efficiency Wet Scrubber - Straight Grate Induration - SO2 

Table J-9: Low Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 

Table J-10: Low Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (20-ppm) + PM 

Table J-11: Low Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (130-ppm) 

Table J-12: High Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (20-ppm) 

Table J-13: High Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (130-ppm)
MPCA BART Analysis 2003

Table J-1: BART Screening Evaluation Summary: Straight Grate Induration - Wet Scrubber and Wet Wall ES

Model Source for Straight Grate Waste Gas Exhaust - SO2 Emissions

General InformationSource Type Straight Grate Waste Gas Exhaust

Pollutant: SO2Existing Pollution Control Equipment Most sources are routed to a wet scrubberControl Cost Summary Control Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed Capital 

Cost $

Annualized

Operating Cost 

$/yr

Pollution 

Control Cost 

$/ton

Air Toxic's 

& AQRV's?

Energ

Impact

Wet Scrubbers High 

Efficiency 95% 26.93 25.58 572,338 1,124,378 43,950 None Mediu

Wet Scrubbers Low 

Efficiency 80% 26.93 21.54 572,338 1,124,378 52,190 None Mediu

Wet Wall ElectroStatic Precipitator (WWESP)

80% 26.93 21.54 3,785,848 2,164,096 100,451 None Low 

Comments

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls St Grate SO2 Summary 
MPCA BART Analysis 2003

Table J-2: BART Screening Evaluation Summary: Grate/Kiln Induration - Wet Scrubber and Wet Wall ESP

Model Source for Grate/Kiln Waste Gas Exhaust - SO2 Emissions

General InformationSource Type Grate/Kiln Waste Gas ExhaustPollutant: SO2Existing Pollution Control Equipment Most sources are routed to a wet scrubber

Control Cost Summary 20 PPM SO2 Case

Control Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution 

Control 

Cost $/ton

Air Toxic's 

& AQRV's?

Energy 

Impacts?

Non-Air Env 

Impacts?

Wet Scrubbers High 

Efficiency 95% 215.4 204.7 1,038,044 2,376,383 11,611 None High Waste-Water

Wet Scrubbers Low 

Efficiency 80% 215.4 172.4 1,038,044 2,376,383 13,788 None High Waste-Water

Wet Wall ElectroStatic 

Precipitator (WWESP)

80% 215.4 172.4 6,010,799 4,155,113 24,108 None Medium Waste-Water

CommentsControl Cost Summary PM + 20 PPM SO2 CaseControl Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution 

Control 

Cost $/ton

Air Toxic's 

& AQRV's?

Energy 

Impacts?

Non-Air Env 

Impacts?

Wet Scrubbers Low 

Efficiency

80%SO2

99% PM 630.6 630.6 1,038,044 2,376,383 3,769 None High Waste-Water

Wet Wall ElectroStatic 

Precipitator (WWESP)

80%SO2

99% PM 678.3 630.6 6,010,799 4,155,113 6,589 None Medium Waste-Water

Comments: Used PM Emission Rate from High Efficiency PM ScrubberControl Cost Summary 130 PPM SO2 CaseControl Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost 

$/yr

Pollution 

Control 

Cost $/ton

Air Toxic's 

& AQRV's?

Energy 

Impacts?

Non-Air Env 

Impacts?

Wet Scrubbers High 

Efficiency 95% 1400.4 1330.3 1,038,044 4,035,263 3,033 None High Waste-Water

Wet Scrubbers Low 

Efficiency 80% 1400.4 1120.3 1,038,044 4,035,263 3,602 None High Waste-Water

Wet Wall ElectroStatic 

Precipitator (WWESP)

80% 1400.4 1120.3 6,010,799 4,984,553 4,449 None Medium Waste-Water

Comments

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate-Kiln SO2 Summary 
MPCA BART Analysis 2003

Table J-3: Wet Wall ESP - Straight Grate Induration - SO2

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 1,438,720

Instrumentation 10% of control device cost (A) 143,872

MN Sales Taxes 3% of control device cost (A) 43,162

Freight 5% of control device cost (A) 71,936

Purchased Equipment Total (B) 18% 1,697,690

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 67,908

Handling & erection 50% of purchased equip cost (B) 848,845

Electrical 8% of purchased equip cost (B) 135,815

Piping 1% of purchased equip cost (B) 16,977

Insulation for ductwork 2% of purchased equip cost (B) 33,954

Painting 2% of purchased equip cost (B) 33,954

Direct Installation Costs 1,137,452

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 2,835,142

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 339,538

Construction & field expenses 20% of purchased equip cost (B) 339,538

Constractor fees 10% of purchased equip cost (B) 169,769

Start-up 1% of purchased equip cost (B) 16,977

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 33,954

Contingencies 3% of purchased equip cost (B) 50,931

Total Indirect Capital Costs 57% 950,706

Total Capital Investment (TCI) = DC + IC 3,785,848

OPERATING COSTS

Direct Operating Costs

Operator 25.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 25,000

Supervisor 15% of operator costs 3,750

Coordinator 33% of operator costs 8,250

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 21,017

Maintenance Materials 1% of purchased equipment costs 16,977

Utilities

Electricity 0.05 $/kW-hr, 365 kW-hr, 8000 hr/yr, 90.0% of capacity 134,390

Water 0.20 $/Mgal, 1,699.8 gpm, 8000 hr/yr, 90.0% of capacity 163,179

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 1,699.8 gpm, 8000 hr/yr, 90.0% of capacity 1,223,845

Reagent (Caustic) 280.00 $/Ton, 16.8 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 18,851

Total Annual Direct Operating Costs, DC 1,615,259

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 40,046

Administration (2% total capital costs) 2% of total capital costs (TCI) 75,717

Property tax (1% total capital costs) 1% of total capital costs (TCI) 37,858

Insurance (1% total capital costs) 1% of total capital costs (TCI) 37,858

Captial Recovery 9% for a 20- year equipment life and a 7% interest rate 357,357

Total Indirect Operating Costs 548,838

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,164,096

Pollutant Removed (tons/yr)B 21.5

Cost per ton of SO2 Removed 100,451

Notes & Assumptions

1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 EPA Cost Manual 6th Ed. 2002

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls St Grate - Wet ESP Page 3 of 24
MPCA BART Analysis 2003

Table J-3: Wet Wall ESP - Straight Grate Induration - SO2 (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 150,000 dscfm 170455 scfm

135 Temp Deg F

12% % Moisture

 acfm 188,865

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 1 hr/8 hr shift 1,000 25,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 25 NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft2

 collector 57,401 ft2 collector area 6,630 $/ft2 collector area; $5775 if < 50,000 ft 2

Maint Mtls 17.5 NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 365.2 kW-hr 2,921,526 134,390 $/kW-hr, 365 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 1700 gpm 815,896 163,179 $/Mgal, 1,699.8 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 16.831 lb/hr 67 18,851 $/Ton, 16.8 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0.000 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 0 Ton 0.857 ton/hr 6,857 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 1700 gpm 815,896 1,223,845 $/Mgal, 1,699.8 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

5 ppm dscfm 150,000 NA 27

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

80% 5.39 Currently assumes 80%.

Emission Reduction T/yr 21.5

Electrical Consumption Requirements Kilowatts

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 188,865 5 0.55 0.9 223.2 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm ∆ P ft H2O Pump Eff Motor Eff

Pump 1 1700 60 0.8 0.9 26.6 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 57,401 111.4 2 4 115.4 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 6.73 lb/hr SO2 2.50 lb NaOH/lb SO2 16.83 lb/hr Caustic

Lime Use 6.73 lb/hr SO2 1.53 lb Lime/lb SO2 10.301 lb/hr Lime

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 188,865 acfm

Area #2 57401.0235 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls St Grate - Wet ESP Page 4 of 24
MPCA BART Analysis 2003

Table J-4: Wet Wall ESP - Grate/Kiln Induration - SO2 (20-ppm)

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 2,284,259

Instrumentation 10% of control device cost (A) 228,426

MN Sales Taxes 3% of control device cost (A) 68,528

Freight 5% of control device cost (A) 114,213

Purchased Equipment Total (B) 18% 2,695,426

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 107,817

Handling & erection 50% of purchased equip cost (B) 1,347,713

Electrical 8% of purchased equip cost (B) 215,634

Piping 1% of purchased equip cost (B) 26,954

Insulation for ductwork 2% of purchased equip cost (B) 53,909

Painting 2% of purchased equip cost (B) 53,909

Direct Installation Costs 1,805,935

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 4,501,361

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 539,085

Construction & field expenses 20% of purchased equip cost (B) 539,085

Constractor fees 10% of purchased equip cost (B) 269,543

Start-up 1% of purchased equip cost (B) 26,954

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 53,909

Contingencies 3% of purchased equip cost (B) 80,863

Total Indirect Capital Costs 57% 1,509,438

Total Capital Investment (TCI) = DC + IC 6,010,799

OPERATING COSTS

Direct Operating Costs

Operator 25.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 25,000

Supervisor 15% of operator costs 3,750

Coordinator 33% of operator costs 8,250

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 36,102

Maintenance Materials 1% of purchased equipment costs 26,954

Utilities

Electricity 0.05 $/kW-hr, 726 kW-hr, 8000 hr/yr, 90.0% of capacity 267,308

Water 0.20 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity 326,359

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity 2,447,689

Reagent (Caustic) 280.00 $/Ton, 134.6 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 150,807

Total Annual Direct Operating Costs, DC 3,292,220

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 55,084

Administration (2% total capital costs) 2% of total capital costs (TCI) 120,216

Property tax (1% total capital costs) 1% of total capital costs (TCI) 60,108

Insurance (1% total capital costs) 1% of total capital costs (TCI) 60,108

Captial Recovery 9% for a 20- year equipment life and a 7% interest rate 567,377

Total Indirect Operating Costs 862,893

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,155,113

Pollutant Removed (tons/yr)B 172.4

Cost per ton of SO2 Removed 24,108

Notes & Assumptions

1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 EPA Cost Manual 6th Ed. 2002

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Wet ESP (20) Page 5 of 24
MPCA BART Analysis 2003

Table J-4: Wet Wall ESP - Grate/Kiln Induration - SO2 (20-ppm) (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow dscfm 300,000 340909 scfm

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 1 hr/8 hr shift 1,000 25,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 25 NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft2

 collector 114,802 ft2 collector area 13,260 $/ft2 collector area; $5775 if < 50,000 ft 2

Maint Mtls 17.5 NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 726.4 kW-hr 5,811,053 267,308 $/kW-hr, 726 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 3400 gpm 1,631,793 326,359 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 134.649 lb/hr 539 150,807 $/Ton, 134.6 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 0 Ton 0.857 ton/hr 6,857 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 3400 gpm 1,631,793 2,447,689 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

20 ppm dscfm 300,000 NA 215.44

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

80% 43.09 Currently assumes 80%.

Emission Reduction T/yr 172.4

Electrical Consumption Requirements Kilowatts

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 377,730 5 0.55 0.9 446.4 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm ∆ P ft H2O Pump Eff Motor Eff

Pump 1 3400 60 0.8 0.9 53.3 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 114,802 222.7 2 4 226.7 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 53.86 lb/hr SO2 2.50 lb NaOH/lb SO2 134.65 lb/hr Caustic

Lime Use 53.86 lb/hr SO2 1.53 lb Lime/lb SO2 82.405 lb/hr Lime

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 377,730 acfm

Area #2 114802.047 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Wet ESP (20) Page 6 of 24
MPCA BART Analysis 2003

Table J-5: Wet Wall ESP - Grate/Kiln Induration - SO2 (20-ppm) + PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 2,284,259

Instrumentation 10% of control device cost (A) 228,426

MN Sales Taxes 3% of control device cost (A) 68,528

Freight 5% of control device cost (A) 114,213

Purchased Equipment Total (B) 18% 2,695,426

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 107,817

Handling & erection 50% of purchased equip cost (B) 1,347,713

Electrical 8% of purchased equip cost (B) 215,634

Piping 1% of purchased equip cost (B) 26,954

Insulation for ductwork 2% of purchased equip cost (B) 53,909

Painting 2% of purchased equip cost (B) 53,909

Direct Installation Costs 1,805,935

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 4,501,361

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 539,085

Construction & field expenses 20% of purchased equip cost (B) 539,085

Constractor fees 10% of purchased equip cost (B) 269,543

Start-up 1% of purchased equip cost (B) 26,954

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 53,909

Contingencies 3% of purchased equip cost (B) 80,863

Total Indirect Capital Costs 57% 1,509,438

Total Capital Investment (TCI) = DC + IC 6,010,799

OPERATING COSTS

Direct Operating Costs

Operator 25.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 25,000

Supervisor 15% of operator costs 3,750

Coordinator 33% of operator costs 8,250

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 36,102

Maintenance Materials 1% of purchased equipment costs 26,954

Utilities

Electricity 0.05 $/kW-hr, 726 kW-hr, 8000 hr/yr, 90.0% of capacity 267,308

Water 0.20 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity 326,359

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity 2,447,689

Reagent (Caustic) 280.00 $/Ton, 134.6 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 150,807

Total Annual Direct Operating Costs, DC 3,292,220

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 55,084

Administration (2% total capital costs) 2% of total capital costs (TCI) 120,216

Property tax (1% total capital costs) 1% of total capital costs (TCI) 60,108

Insurance (1% total capital costs) 1% of total capital costs (TCI) 60,108

Captial Recovery 9% for a 20- year equipment life and a 7% interest rate 567,377

Total Indirect Operating Costs 862,893

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,155,113

Pollutant Removed SO2 + PM (tons/yr)B 630.6

Cost per ton of SO2 + PM Removed 6,589

Notes & Assumptions

1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 EPA Cost Manual 6th Ed. 2002

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Wet ESP 20 SO2+PM Page 7 of 24
MPCA BART Analysis 2003

Table J-5: Wet Wall ESP - Grate/Kiln Induration - SO2 (20-ppm) + PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cell

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340909 scfm

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 1 hr/8 hr shift 1,000 25,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 25 NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft2 collector 114,802 ft2 collector area 13,260 $/ft2 collector area; $5775 if < 50,000 ft2

Maint Mtls 17.5 NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 726.4 kW-hr 5,811,053 267,308 $/kW-hr, 726 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 3400 gpm 1,631,793 326,359 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 134.649 lb/hr 539 150,807 $/Ton, 134.6 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 0 Ton 0.857 ton/hr 6,857 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 3400 gpm 1,631,793 2,447,689 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost facto

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

20 ppm 300,000 dscfm NA 215.44 SO2 + PM 678.30

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

80% 43.09 Currently assumes 80%.

Emission Reduction SO2 T/yr 172.4

Emission Reduction PM T/yr 458.2

Emission Reduction SO2 + PM T/yr 630.6

Electrical Consumption Requirements Kilowatts

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 377,730 5 0.55 0.9 446.4 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm ∆ P ft H2O Pump Eff Motor Eff

Pump 1 3400 60 0.8 0.9 53.3 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 114,802 222.7 2 4 226.7 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 53.86 lb/hr SO2 2.50 lb NaOH/lb SO2 134.65 lb/hr Caustic

Lime Use 53.86 lb/hr SO2 1.53 lb Lime/lb SO2 82.405 lb/hr Lime

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 377,730 acfm

Area #2 114802.047 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Wet ESP 20 SO2+PM Page 8 of 24
MPCA BART Analysis 2003

Table J-6: Wet Wall ESP - Grate/Kiln Induration - SO2 (130-ppm)

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 2,284,259

Instrumentation 10% of control device cost (A) 228,426

MN Sales Taxes 3% of control device cost (A) 68,528

Freight 5% of control device cost (A) 114,213

Purchased Equipment Total (B) 18% 2,695,426

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 107,817

Handling & erection 50% of purchased equip cost (B) 1,347,713

Electrical 8% of purchased equip cost (B) 215,634

Piping 1% of purchased equip cost (B) 26,954

Insulation for ductwork 2% of purchased equip cost (B) 53,909

Painting 2% of purchased equip cost (B) 53,909

Direct Installation Costs 1,805,935

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 4,501,361

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 539,085

Construction & field expenses 20% of purchased equip cost (B) 539,085

Constractor fees 10% of purchased equip cost (B) 269,543

Start-up 1% of purchased equip cost (B) 26,954

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 53,909

Contingencies 3% of purchased equip cost (B) 80,863

Total Indirect Capital Costs 57% 1,509,438

Total Capital Investment (TCI) = DC + IC 6,010,799

OPERATING COSTS

Direct Operating Costs

Operator 25.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capac 25,000

Supervisor 15% of operator costs 3,750

Coordinator 33% of operator costs 8,250

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 36,102

Maintenance Materials 1% of purchased equipment costs 26,954

Utilities

Electricity 0.05 $/kW-hr, 726 kW-hr, 8000 hr/yr, 90.0% of capaci 267,308

Water 0.20 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capac 326,359

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capac 2,447,689

Reagent (Caustic) 280.00 $/Ton, 875.2 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 w 980,247

Total Annual Direct Operating Costs, DC 4,121,660

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 55,084

Administration (2% total capital costs) 2% of total capital costs (TCI) 120,216

Property tax (1% total capital costs) 1% of total capital costs (TCI) 60,108

Insurance (1% total capital costs) 1% of total capital costs (TCI) 60,108

Captial Recovery 9% for a 20- year equipment life and a 7% interest rat 567,377

Total Indirect Operating Costs 862,893

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,984,553

Pollutant Removed (tons/yr)B 1,120.3

Cost per ton of SO2 Removed 4,449

Notes & Assumptions

1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 EPA Cost Manual 6th Ed. 2002

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Wet ESP (130) Page 9 of 24
MPCA BART Analysis 2003

Table J-6: Wet Wall ESP - Grate/Kiln Induration - SO2 (130-ppm) (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340909 scfm

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 1 hr/8 hr shift 1,000 25,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 25 NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft2

 collector 114,802 ft2 collector area 13,260 $/ft2 collector area; $5775 if < 50,000 ft 2

Maint Mtls 17.5 NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 726.4 kW-hr 5,811,053 267,308 $/kW-hr, 726 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 3400 gpm 1,631,793 326,359 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 875.221 lb/hr 3,501 980,247 $/Ton, 875.2 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 0 Ton 0.857 ton/hr 6,857 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 3400 gpm 1,631,793 2,447,689 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

130 ppm dscfm 300,000 NA 1400.35

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

80% 280.07 Currently assumes 80%.

Emission Reduction T/yr 1120.3

Electrical Consumption Requirements Kilowatts

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 377,730 5 0.55 0.9 446.4 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm ∆ P ft H2O Pump Eff Motor Eff

Pump 1 3400 60 0.8 0.9 53.3 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 114,802 222.7 2 4 226.7 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 350.09 lb/hr SO2 2.50 lb NaOH/lb SO2 875.22 lb/hr Caustic

Lime Use 350.09 lb/hr SO2 1.53 lb Lime/lb SO2 535.635 lb/hr Lime

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 377,730 acfm

Area #2 114802.047 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Wet ESP (130) Page 10 of 24
MPCA BART Analysis 2003

Table J-7: Low Efficiency Wet Scrubber - Straight Grate Induration - SO2

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 220,469

Instrumentation 10% of control device cost (A) 22,047

MN Sales Taxes 3.0% of control device cost (A) 6,614

Freight 5% of control device cost (A) 11,023

Purchased Equipment Total (B) 18% 260,153

Installation

Foundations & supports 12% of purchased equip cost (B) 31,218

Handling & erection 40% of purchased equip cost (B) 104,061

Electrical 1% of purchased equip cost (B) 2,602

Piping 30% of purchased equip cost (B) 78,046

Insulation 1% of purchased equip cost (B) 2,602

Painting 1% of purchased equip cost (B) 2,602

Installation Total 85% 221,130

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 481,284

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 26,015

Construction & field expenses 10% of purchased equip cost (B) 26,015

Construction fee 10% of purchased equip cost (B) 26,015

Start-up 1% of purchased equip cost (B) 2,602

Performance test 1% of purchased equip cost (B) 2,602

Contingencies 3% of purchased equip cost (B) 7,805

Total Indirect Capital Costs, IC 35% 91,054

Total Capital Investment (TCI) = DC + IC 572,338

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 280 $/Ton, 16.8 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 18,851

Reagent #2 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity 220,292

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 698 kW-hr, 8000 hr/yr, 90.0% of capacity 231,287

Total Annual Direct Operating Costs 500,867

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 11,447

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,723

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,723

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 81,488 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 623,511

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,124,378

Pollutant Removed (tons/yr)B 22

Cost per ton of SO2 Removed 52,190

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls St Grate - Low Scrub Page 11 of 24
MPCA BART Analysis 2003

Table J-7: Low Efficiency Wet Scrubber - Straight Grate Induration - SO2 (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 150,000 dscfm 170455 scfm

135 Temp Deg F

12% % Moisture

 acfm 188,865

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 698.3 kW-hr 5,027,971 231,287 $/kW-hr, 698 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 340.0 gpm 146,861 29,372 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 16.83 lb/hr 67 18,851 $/Ton, 16.8 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0.000 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 340.0 gpm 146,861 220,292 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

5 ppm 150,000 dscfm NA 26.93 

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure 80% T/yr Currently assumes 80%.

80% 5 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 21.5 Assuming 80% control.

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 169,978 12 0.55 0.7 619.9 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 1,700 125 0.8 0.7 71.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 340.0 62.5 0.8 0.7 7.1 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 6.73 lb/hr SO2 2.50 lb NaOH/lb SO2 16.83 lb/hr Caustic

Lime Use 6.73 lb/hr SO2 1.53 lb Lime/lb SO2 10.30 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls St Grate - Low Scrub Page 12 of 24
MPCA BART Analysis 2003

Table J-8: High Efficiency Wet Scrubber - Straight Grate Induration - SO2

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 220,469

Instrumentation 10% of control device cost (A) 22,047

MN Sales Taxes 3.0% of control device cost (A) 6,614

Freight 5% of control device cost (A) 11,023

Purchased Equipment Total (B) 18% 260,153

Installation

Foundations & supports 12% of purchased equip cost (B) 31,218

Handling & erection 40% of purchased equip cost (B) 104,061

Electrical 1% of purchased equip cost (B) 2,602

Piping 30% of purchased equip cost (B) 78,046

Insulation 1% of purchased equip cost (B) 2,602

Painting 1% of purchased equip cost (B) 2,602

Installation Total 85% 221,130

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 481,284

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 26,015

Construction & field expenses 10% of purchased equip cost (B) 26,015

Construction fee 10% of purchased equip cost (B) 26,015

Start-up 1% of purchased equip cost (B) 2,602

Performance test 1% of purchased equip cost (B) 2,602

Contingencies 3% of purchased equip cost (B) 7,805

Total Indirect Capital Costs, IC 35% 91,054

Total Capital Investment (TCI) = DC + IC 572,338

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 280 $/Ton, 16.8 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 18,851

Reagent #2 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity 220,292

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 698 kW-hr, 8000 hr/yr, 90.0% of capacity 231,287

Total Annual Direct Operating Costs 500,867

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 11,447

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,723

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,723

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 81,488

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 623,511

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,124,378

Pollutant Removed (tons/yr)B 26

Cost per ton of SO2 Removed 43,950

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls St Grate - High Scrub Page 13 of 24
MPCA BART Analysis 2003

Table J-8: High Efficiency Wet Scrubber - Straight Grate Induration - SO2 (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 150,000 dscfm 170455 scfm

135 Temp Deg F

12% % Moisture

 acfm 188,865

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 698.3 kW-hr 5,027,971 231,287 $/kW-hr, 698 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 340.0 gpm 146,861 29,372 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 16.83 lb/hr 67 18,851 $/Ton, 16.8 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 340.0 gpm 146,861 220,292 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

5 ppm 150,000 dscfm NA 26.9 

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

95% 1 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 25.6 Assuming 95% control.

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 169,978 12 0.55 0.7 619.9 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 1,700 125 0.8 0.7 71.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 340.0 62.5 0.8 0.7 7.1 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 6.73 lb/hr SO2 2.50 lb NaOH/lb SO2 16.83 lb/hr Caustic

Lime Use 6.73 lb/hr SO2 1.53 lb Lime/lb SO2 10.30 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls St Grate - High Scrub Page 14 of 24
MPCA BART Analysis 2003

Table J-9: Low Efficiency Wet Scrubber - Grate/Kiln Induration - SO2(20 ppm)

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 399,863

Instrumentation 10% of control device cost (A) 39,986

MN Sales Taxes 3.0% of control device cost (A) 11,996

Freight 5% of control device cost (A) 19,993

Purchased Equipment Total (B) 18% 471,838

Installation

Foundations & supports 12% of purchased equip cost (B) 56,621

Handling & erection 40% of purchased equip cost (B) 188,735

Electrical 1% of purchased equip cost (B) 4,718

Piping 30% of purchased equip cost (B) 141,552

Insulation 1% of purchased equip cost (B) 4,718

Painting 1% of purchased equip cost (B) 4,718

Installation Total 85% 401,063

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 872,901

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,184

Construction & field expenses 10% of purchased equip cost (B) 47,184

Construction fee 10% of purchased equip cost (B) 47,184

Start-up 1% of purchased equip cost (B) 4,718

Performance test 1% of purchased equip cost (B) 4,718

Contingencies 3% of purchased equip cost (B) 14,155

Total Indirect Capital Costs, IC 35% 165,143

Total Capital Investment (TCI) = DC + IC 1,038,044

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 280 $/Ton, 134.6 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 150,807

Reagent #2 NA - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity 440,584

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity 462,573

Total Annual Direct Operating Costs 1,084,402

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,761

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,380

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,380

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 147,794

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,291,981

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,376,383

Pollutant Removed (tons/yr)B 172

Cost per ton of SO2 Removed 13,788

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Low Scrub (20) Page 15 of 24
MPCA BART Analysis 2003

Table J-9: Low Efficiency Wet Scrubber - Grate/Kiln Induration - SO2(20 ppm) (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow dscfm 300,000 340,909 scfm

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1396.7 kW-hr 10,055,941 462,573 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 679.9 gpm 293,723 58,745 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 134.65 lb/hr 539 150,807 $/Ton, 134.6 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 679.9 gpm 293,723 440,584 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

20 ppm 300,000 dscfm NA 215.4 

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure 80% T/yr Currently assumes 80%.

80% 43 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 172.4 Assuming 80% control.

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 339,957 12 0.55 0.7 1239.7 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 3,400 125 0.8 0.7 142.7 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 679.9 62.5 0.8 0.7 14.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 53.86 lb/hr SO2 2.50 lb NaOH/lb SO2 134.65 lb/hr Caustic

Lime Use 53.86 lb/hr SO2 1.53 lb Lime/lb SO2 82.41 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Low Scrub (20) Page 16 of 24
MPCA BART Analysis 2003

Table J-10: Low Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (20-ppm) + PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 399,863

Instrumentation 10% of control device cost (A) 39,986

MN Sales Taxes 3.0% of control device cost (A) 11,996

Freight 5% of control device cost (A) 19,993

Purchased Equipment Total (B) 18% 471,838

Installation

Foundations & supports 12% of purchased equip cost (B) 56,621

Handling & erection 40% of purchased equip cost (B) 188,735

Electrical 1% of purchased equip cost (B) 4,718

Piping 30% of purchased equip cost (B) 141,552

Insulation 1% of purchased equip cost (B) 4,718

Painting 1% of purchased equip cost (B) 4,718

Installation Total 85% 401,063

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 872,901

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,184

Construction & field expenses 10% of purchased equip cost (B) 47,184

Construction fee 10% of purchased equip cost (B) 47,184

Start-up 1% of purchased equip cost (B) 4,718

Performance test 1% of purchased equip cost (B) 4,718

Contingencies 3% of purchased equip cost (B) 14,155

Total Indirect Capital Costs, IC 35% 165,143

Total Capital Investment (TCI) = DC + IC 1,038,044

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 280 $/Ton, 134.6 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 150,807

Reagent #2 NA - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity 440,584

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity 462,573

Total Annual Direct Operating Costs 1,084,402

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,761

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,380

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,380

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 147,794

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,291,981

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,376,383

Pollutant Removed SO2 + PM (tons/yr)B 631

Cost per ton of SO2 and PM Removed 3,769

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2 Used PM Emission Rate from Hi Eff Scrubber

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Low Scrub SO2+PM Page 17 of 24
MPCA BART Analysis 2003

Table J-10: Low Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (20-ppm) + PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

Amount Required 0 ft

3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340,909 scfm

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1396.7 kW-hr 10,055,941 462,573 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 679.9 gpm 293,723 58,745 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 134.65 lb/hr 539 150,807 $/Ton, 134.6 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 679.9 gpm 293,723 440,584 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft

3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost facto

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

20 ppm 300,000 dscfm NA 215.4 SO2 + PM 678.30

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure 80% T/yr Currently assumes 80%.

80% 43 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction SO2 T/yr 172.4 Assuming 80% control.

Emission Reduction PM T/yr 458.2

Emission Reduction SO2 + PM T/yr 630.6

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 339,957 12 0.55 0.7 1239.7 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 3,400 125 0.8 0.7 142.7 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 679.9 62.5 0.8 0.7 14.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 53.86 lb/hr SO2 2.50 lb NaOH/lb SO2 134.65 lb/hr Caustic

Lime Use 53.86 lb/hr SO2 1.53 lb Lime/lb SO2 82.41 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Low Scrub SO2+PM Page 18 of 24
MPCA BART Analysis 2003

Table J-11: Low Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (130-ppm)

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 399,863

Instrumentation 10% of control device cost (A) 39,986

MN Sales Taxes 3.0% of control device cost (A) 11,996

Freight 5% of control device cost (A) 19,993

Purchased Equipment Total (B) 18% 471,838

Installation

Foundations & supports 12% of purchased equip cost (B) 56,621

Handling & erection 40% of purchased equip cost (B) 188,735

Electrical 1% of purchased equip cost (B) 4,718

Piping 30% of purchased equip cost (B) 141,552

Insulation 1% of purchased equip cost (B) 4,718

Painting 1% of purchased equip cost (B) 4,718

Installation Total 85% 401,063

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 872,901

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,184

Construction & field expenses 10% of purchased equip cost (B) 47,184

Construction fee 10% of purchased equip cost (B) 47,184

Start-up 1% of purchased equip cost (B) 4,718

Performance test 1% of purchased equip cost (B) 4,718

Contingencies 3% of purchased equip cost (B) 14,155

Total Indirect Capital Costs, IC 35% 165,143

Total Capital Investment (TCI) = DC + IC 1,038,044

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 280 $/Ton, 875.2 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 980,247

Reagent #2 NA - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity 440,584

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity 462,573

Total Annual Direct Operating Costs 1,913,842

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,761

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,380

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,380

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 147,794

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,121,421

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,035,263

Pollutant Removed (tons/yr)B 1,120

Cost per ton of SO2 Removed 3,602

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Low Scrub (130) Page 19 of 24
MPCA BART Analysis 2003

Table J-11: Low Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (130-ppm) (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340,909 scfm

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1396.7 kW-hr 10,055,941 462,573 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 679.9 gpm 293,723 58,745 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 875.22 lb/hr 3,501 980,247 $/Ton, 875.2 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 679.9 gpm 293,723 440,584 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

130 ppm 300,000 dscfm NA 1,400.4 

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure 80% T/yr Currently assumes 80%.

80% 280 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 1120.3 Assuming 80% control.

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 339,957 12 0.55 0.7 1239.7 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 3,400 125 0.8 0.7 142.7 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 679.9 62.5 0.8 0.7 14.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 350.09 lb/hr SO2 2.50 lb NaOH/lb SO2 875.22 lb/hr Caustic

Lime Use 350.09 lb/hr SO2 1.53 lb Lime/lb SO2 535.64 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - Low Scrub (130) Page 20 of 24
MPCA BART Analysis 2003

Table J-12: High Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (20-ppm)

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 399,863

Instrumentation 10% of control device cost (A) 39,986

MN Sales Taxes 3.0% of control device cost (A) 11,996

Freight 5% of control device cost (A) 19,993

Purchased Equipment Total (B) 18% 471,838

Installation

Foundations & supports 12% of purchased equip cost (B) 56,621

Handling & erection 40% of purchased equip cost (B) 188,735

Electrical 1% of purchased equip cost (B) 4,718

Piping 30% of purchased equip cost (B) 141,552

Insulation 1% of purchased equip cost (B) 4,718

Painting 1% of purchased equip cost (B) 4,718

Installation Total 85% 401,063

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 872,901

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,184

Construction & field expenses 10% of purchased equip cost (B) 47,184

Construction fee 10% of purchased equip cost (B) 47,184

Start-up 1% of purchased equip cost (B) 4,718

Performance test 1% of purchased equip cost (B) 4,718

Contingencies 3% of purchased equip cost (B) 14,155

Total Indirect Capital Costs, IC 35% 165,143

Total Capital Investment (TCI) = DC + IC 1,038,044

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 280 $/Ton, 134.6 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 150,807

Reagent #2 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity 440,584

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity 462,573

Total Annual Direct Operating Costs 1,084,402

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,761

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,380

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,380

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 147,794

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,291,981

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,376,383

Pollutant Removed (tons/yr)B 205

Cost per ton of SO2 Removed 11,611

Notes & Assumptions

3 EPA Air Pollution Control Cost Manual 6th Ed 2002

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - High Scrub (20) Page 21 of 24
MPCA BART Analysis 2003

Table J-12: High Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (20-ppm) (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340,909 scfm

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1396.7 kW-hr 10,055,941 462,573 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 679.9 gpm 293,723 58,745 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 134.65 lb/hr 539 150,807 $/Ton, 134.6 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 679.9 gpm 293,723 440,584 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

20 ppm 300,000 dscfm NA 215.4 

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

95% 11 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 204.7 Assuming 95% control.

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 339,957 12 0.55 0.7 1239.7 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 3,400 125 0.8 0.7 142.7 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 679.9 62.5 0.8 0.7 14.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 53.86 lb/hr SO2 2.50 lb NaOH/lb SO2 134.65 lb/hr Caustic

Lime Use 53.86 lb/hr SO2 1.53 lb Lime/lb SO2 82.41 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - High Scrub (20) Page 22 of 24
MPCA BART Analysis 2003

Table J-13: High Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (130-ppm)

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 399,863

Instrumentation 10% of control device cost (A) 39,986

MN Sales Taxes 3.0% of control device cost (A) 11,996

Freight 5% of control device cost (A) 19,993

Purchased Equipment Total (B) 18% 471,838

Installation

Foundations & supports 12% of purchased equip cost (B) 56,621

Handling & erection 40% of purchased equip cost (B) 188,735

Electrical 1% of purchased equip cost (B) 4,718

Piping 30% of purchased equip cost (B) 141,552

Insulation 1% of purchased equip cost (B) 4,718

Painting 1% of purchased equip cost (B) 4,718

Installation Total 85% 401,063

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 872,901

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,184

Construction & field expenses 10% of purchased equip cost (B) 47,184

Construction fee 10% of purchased equip cost (B) 47,184

Start-up 1% of purchased equip cost (B) 4,718

Performance test 1% of purchased equip cost (B) 4,718

Contingencies 3% of purchased equip cost (B) 14,155

Total Indirect Capital Costs, IC 35% 165,143

Total Capital Investment (TCI) = DC + IC 1,038,044

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 280 $/Ton, 875.2 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 980,247

Reagent #2 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity 440,584

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity 462,573

Total Annual Direct Operating Costs 1,913,842

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,761

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,380

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,380

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 147,794

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,121,421

Total Annual Cost (Annualized Capital Cost + Operating Cost) 4,035,263

Pollutant Removed (tons/yr)B 1,330

Cost per ton of SO2 Removed 3,033

Notes & Assumptions

3 EPA Air Pollution Control Cost Manual 6th Ed 2002

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - High Scrub (130) Page 23 of 24
MPCA BART Analysis 2003

Table J-13: High Efficiency Wet Scrubber - Grate/Kiln Induration - SO2 (130-ppm) (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340,909 scfm

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1396.7 kW-hr 10,055,941 462,573 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.2 Mgal 679.9 gpm 293,723 58,745 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.25 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 875.22 lb/hr 3,501 980,247 $/Ton, 875.2 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/ton, 4 gr/scf, 50 Mscfm, 8460 hr/yr

WW Treat 1.5 Mgal 679.9 gpm 293,723 440,584 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

130 ppm 300,000 dscfm NA 1,400.4

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

95% 70 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 1330.3 Assuming 95% control.

Flow acfm ∆ P in H2O Blower Eff Motor Eff kW

Blower 339,957 12 0.55 0.7 1239.7 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 3,400 125 0.8 0.7 142.7 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 679.9 62.5 0.8 0.7 14.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 350.09 lb/hr SO2 2.50 lb NaOH/lb SO2 875.22 lb/hr Caustic

Lime Use 350.09 lb/hr SO2 1.53 lb Lime/lb SO2 535.64 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment J.xls Grate, Kiln - High Scrub (130) Page 24 of 24
ATTACHMENT K 

Model BART Cost Analysis - Induration Furnace PM Emissions 

List of Tables: 

Table K-1: BART Screening Evaluation Summary: Straight Grate Induration - Wet Scrubber, ESP, 

Wet Wall ESP, Fabric Filters and Multiclones 

Table K-2: BART Screening Evaluation Summary: Grate/Kiln Induration - Wet Scrubber, ESP, Wet 

Wall ESP, Fabric Filters and Multiclones 

Table K-3: Low Efficiency Wet Scrubber - Straight Grate Induration - PM 

Table K-4: High Efficiency Wet Scrubber - Straight Grate Induration - PM 

Table K-5: Low Efficiency Wet Scrubber - Grate/Kiln Induration - PM 

Table K-6: High Efficiency Wet Scrubber - Grate/Kiln Induration - PM 

Table K-7: ESP - Straight Grate Induration - PM 

Table K-8: ESP - Grate/Kiln Induration - PM 

Table K-9: Wet Wall ESP - Straight Grate Induration - PM 

Table K-10: Wet Wall ESP - Grate/Kiln Induration - PM 

Table K-11: Baghouse - Straight Grate Induration - PM 

Table K-12: Baghouse - Grate/Kiln Induration - PM 

Table K-13: Multiclone - Straight Grate Induration - PM 

Table K-14: Multiclone - Grate/Kiln Induration - PM 
MPCA BART Anaylsis 2003

Table K-1: BART Screening Evaluation Summary: Straight Grate Induration - Wet Scrubber, ESP, We

and Multiclones

Model Source for Straight Grate Waste Gas Exhaust - PM Emissions

General InformationSource Type Straight Grate Waste Gas ExhaustPollutant: Particulate Matter (PM10)Existing Pollution Control Equipment Most sources are routed to a wet scrubberControl Cost SummaryControl Technology

Control 

Eff % Emissions T/y

Emission 

Reduction 

T/yr

Installed 

Capital Cost $

Annualized 

Operating 

Cost $/yr

Pollution 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energ

Impact

Wet Scrubbers High 

Efficiency 99% 41.1 40.7 572,338 1,086,676 26,679 None Mediu

Wet Scrubbers Low 

Efficiency 92% 41.1 37.9 572,338 1,086,676 28,709 None Mediu

Dry ElectroStatic 

Precipitators (ESP) 99% 41.1 40.7 3,675,579 701,132 17,214 None Low 

Wet Wall ElectroStatic 

Precipitator (WWESP) 99% 41.1 40.7 3,785,848 2,141,976 52,588 None Low 

Fabric Filters 

(Baghouses) 99% 41.1 40.7 2,147,481 1,213,453 29,792 None High 

Multiclones 80% 41.1 32.9 272,391 685,529 20,828 None High 

Comments

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate PM Summary 
MPCA BART Anaylsis 2003

Table K-2: BART Screening Evaluation Summary: Grate/Kiln Induration - Wet Scrubber, ESP, Wet W

Multiclones

Model Source for Grate/Kiln Waste Gas Exhaust - PM Emissions

General InformationSource Type Grate/Kiln Waste Gas ExhaustPollutant: Particulate Matter (PM10)Existing Pollution Control Equipment Most sources have a wet scrubber or WW ESPControl Cost SummaryControl Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed 

Capital Cost $

Annualized 

Operating 

Cost $/yr

Pollution 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts

Wet Scrubbers High 

Efficiency 99% 514.3 509.1 1,038,044 2,074,768 4,075 None Medium 

Wet Scrubbers Low 

Efficiency 95% 514.3 488.6 1,038,044 2,074,768 4,247 None Medium 

Dry ElectroStatic 

Precipitators (ESP) 99% 514.3 509.1 5,835,727 1,137,133 2,233 None Low 

Wet Wall ElectroStatic 

Precipitator (WWESP) 99% 514.3 509.1 6,010,799 3,997,767 7,852 None Low 

Fabric Filters 

(Baghouses) 99% 514.3 509.1 4,294,971 2,289,600 4,497 None High 

Multiclones 80% 514.3 411.4 533,041 1,333,858 3,242 None High 

Comments

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate-Kiln PM Summary 
MPCA BART Anaylsis 2003

Table K-3: Low Efficiency Wet Scrubber - Straight Grate Induration - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 220,469

Instrumentation 10% of control device cost (A) 22,047

MN Sales Taxes 3.0% of control device cost (A) 6,614

Freight 5% of control device cost (A) 11,023

Purchased Equipment Total (B) 18% 260,153

Installation

Foundations & supports 12% of purchased equip cost (B) 31,218

Handling & erection 40% of purchased equip cost (B) 104,061

Electrical 1% of purchased equip cost (B) 2,602

Piping 30% of purchased equip cost (B) 78,046

Insulation 1% of purchased equip cost (B) 2,602

Painting 1% of purchased equip cost (B) 2,602

Installation Total 85% 221,130

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 481,284

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 26,015

Construction & field expenses 10% of purchased equip cost (B) 26,015

Construction fee 10% of purchased equip cost (B) 26,015

Start-up 1% of purchased equip cost (B) 2,602

Performance test 1% of purchased equip cost (B) 2,602

Contingencies 3% of purchased equip cost (B) 7,805

Total Indirect Capital Costs, IC 35% 91,054

Total Capital Investment (TCI) = DC + IC 572,338

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 NA $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Reagent #2 NA $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity 220,292

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 698 kW-hr, 8000 hr/yr, 90.0% of capacity 231,287

Total Annual Direct Operating Costs 482,016

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 11,447

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,723

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,723

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 81,488 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 604,660

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,086,676

Pollutant Removed (tons/yr)B 38

Cost per ton of PM Removed 28,709

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - Low Wet Scrub Page 3 of 26
MPCA BART Anaylsis 2003

Table K-3: Low Efficiency Wet Scrubber - Straight Grate Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 150,000 dscfm 170455 scfm

135 Temp Deg F

12% % Moisture

 acfm 188,865

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 698 kW-hr 5,027,971 231,287 $/kW-hr, 698 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 340.0 gpm 146,861 32,309 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0.000 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0.000 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 340.0 gpm 146,861 220,292 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.008 gr/dscf dscfm NA 150,000 41 

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

92% 3.3 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 37.9 Assuming 92% control (range 90-95%)

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 169,978 12 0.55 0.7 619.9 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 1,700 125 0.8 0.7 71.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 340.0 62.5 0.8 0.7 7.1 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - Low Wet Scrub Page 4 of 26
MPCA BART Anaylsis 2003

Table K-4: High Efficiency Wet Scrubber - Straight Grate Induration - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 220,469

Instrumentation 10% of control device cost (A) 22,047

MN Sales Taxes 3.0% of control device cost (A) 6,614

Freight 5% of control device cost (A) 11,023

Purchased Equipment Total (B) 18% 260,153

Installation

Foundations & supports 12% of purchased equip cost (B) 31,218

Handling & erection 40% of purchased equip cost (B) 104,061

Electrical 1% of purchased equip cost (B) 2,602

Piping 30% of purchased equip cost (B) 78,046

Insulation 1% of purchased equip cost (B) 2,602

Painting 1% of purchased equip cost (B) 2,602

Installation Total 85% 221,130

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 481,284

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 26,015

Construction & field expenses 10% of purchased equip cost (B) 26,015

Construction fee 10% of purchased equip cost (B) 26,015

Start-up 1% of purchased equip cost (B) 2,602

Performance test 1% of purchased equip cost (B) 2,602

Contingencies 3% of purchased equip cost (B) 7,805

Total Indirect Capital Costs, IC 35% 91,054

Total Capital Investment (TCI) = DC + IC 572,338

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 NA $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Reagent #2 NA $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity 220,292

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 698 kW-hr, 8000 hr/yr, 90.0% of capacity 231,287

Total Annual Direct Operating Costs 482,016

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 11,447

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,723

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,723

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 81,488 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 604,660

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,086,676

Pollutant Removed (tons/yr)B 41

Cost per ton of PM Removed 26,679

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - High Wet Scrub Page 5 of 26
MPCA BART Anaylsis 2003

Table K-4: High Efficiency Wet Scrubber - Straight Grate Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 150,000 dscfm 170455 scfm

135 Temp Deg F

12% % Moisture

 acfm 188,865

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 698 kW-hr 5,027,971 231,287 $/kW-hr, 698 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 340.0 gpm 146,861 32,309 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 340.0 gpm 146,861 220,292 $/Mgal, 340.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.008 gr/dscf dscfm NA 150,000 41 

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 0.4 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 40.7 Assuming 99% control.

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 169,978 12 0.55 0.7 619.9 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 1,700 125 0.8 0.7 71.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 340.0 62.5 0.8 0.7 7.1 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - High Wet Scrub Page 6 of 26
MPCA BART Anaylsis 2003

Table K-5: Low Efficiency Wet Scrubber - Grate/Kiln Induration - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 399,863

Instrumentation 10% of control device cost (A) 39,986

MN Sales Taxes 3.0% of control device cost (A) 11,996

Freight 5% of control device cost (A) 19,993

Purchased Equipment Total (B) 18% 471,838

Installation

Foundations & supports 12% of purchased equip cost (B) 56,621

Handling & erection 40% of purchased equip cost (B) 188,735

Electrical 1% of purchased equip cost (B) 4,718

Piping 30% of purchased equip cost (B) 141,552

Insulation 1% of purchased equip cost (B) 4,718

Painting 1% of purchased equip cost (B) 4,718

Installation Total 85% 401,063

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 872,901

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,184

Construction & field expenses 10% of purchased equip cost (B) 47,184

Construction fee 10% of purchased equip cost (B) 47,184

Start-up 1% of purchased equip cost (B) 4,718

Performance test 1% of purchased equip cost (B) 4,718

Contingencies 3% of purchased equip cost (B) 14,155

Total Indirect Capital Costs, IC 35% 165,143

Total Capital Investment (TCI) = DC + IC 1,038,044

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 NA $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Reagent #2 NA - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity 440,584

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity 462,573

Total Annual Direct Operating Costs 933,595

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,761

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,380

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,380

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 147,794 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,141,173

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,074,768

Pollutant Removed (tons/yr)B 489

Cost per ton of PM Removed 4,247

Notes & Assumptions

1 1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate, Kiln - Low Wet Scrub Page 7 of 26
MPCA BART Anaylsis 2003

Table K-5: Low Efficiency Wet Scrubber - Grate/Kiln Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340,909 scfm

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1397 kW-hr 10,055,941 462,573 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 679.9 gpm 293,723 64,619 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 679.9 gpm 293,723 440,584 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.05 gr/dscf dscfm NA 300,000 514.3 

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

95% 26 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 488.6 Assuming 92% control (range 90-95%)

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 339,957 12 0.55 0.7 1239.7 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 3,400 125 0.8 0.7 142.7 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 679.9 62.5 0.8 0.7 14.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate, Kiln - Low Wet Scrub Page 8 of 26
MPCA BART Anaylsis 2003

Table K-6: High Efficiency Wet Scrubber - Grate/Kiln Induration - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 399,863

Instrumentation 10% of control device cost (A) 39,986

MN Sales Taxes 3.0% of control device cost (A) 11,996

Freight 5% of control device cost (A) 19,993

Purchased Equipment Total (B) 18% 471,838

Installation

Foundations & supports 12% of purchased equip cost (B) 56,621

Handling & erection 40% of purchased equip cost (B) 188,735

Electrical 1% of purchased equip cost (B) 4,718

Piping 30% of purchased equip cost (B) 141,552

Insulation 1% of purchased equip cost (B) 4,718

Painting 1% of purchased equip cost (B) 4,718

Installation Total 85% 401,063

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 872,901

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 47,184

Construction & field expenses 10% of purchased equip cost (B) 47,184

Construction fee 10% of purchased equip cost (B) 47,184

Start-up 1% of purchased equip cost (B) 4,718

Performance test 1% of purchased equip cost (B) 4,718

Contingencies 3% of purchased equip cost (B) 14,155

Total Indirect Capital Costs, IC 35% 165,143

Total Capital Investment (TCI) = DC + IC 1,038,044

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 NA $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Reagent #2 NA $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity 440,584

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity 462,573

Total Annual Direct Operating Costs 933,595

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 20,761

Property tax (1% total capital costs) 1% of total capital costs (TCI) 10,380

Insurance (1% total capital costs) 1% of total capital costs (TCI) 10,380

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 147,794 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 1,141,173

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,074,768

Pollutant Removed (tons/yr)B 509

Cost per ton of PM Removed 4,075

Notes & Assumptions

1 1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate, Kiln - High Wet Scrub Page 9 of 26
MPCA BART Anaylsis 2003

Table K-6: High Efficiency Wet Scrubber - Grate/Kiln Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm scfm 340,909

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1397 kW-hr 10,055,941 462,573 $/kW-hr, 1,397 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 679.9 gpm 293,723 64,619 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 679.9 gpm 293,723 440,584 $/Mgal, 679.9 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.05 gr/dscf dscfm 300,000 NA 514.3 

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 5 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 509.1 Assuming 99% control.

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 339,957 12 0.55 0.7 1239.7 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm P ft H2O Pump Eff Motor Eff

Circ Pump 3,400 125 0.8 0.7 142.7 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 679.9 62.5 0.8 0.7 14.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate, Kiln - High Wet Scrub Page 10 of 26
MPCA BART Anaylsis 2003

Table K-7: ESP - Straight Grate Induration - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 1,396,815

Instrumentation 10% of control device cost (A) 139,682

MN Sales Taxes 3% of control device cost (A) 41,904

Freight 5% of control device cost (A) 69,841

Purchased Equipment Total (B) 18% 1,648,242

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 65,930

Handling & erection 50% of purchased equip cost (B) 824,121

Electrical 8% of purchased equip cost (B) 131,859

Piping 1% of purchased equip cost (B) 16,482

Insulation for ductwork 2% of purchased equip cost (B) 32,965

Painting 2% of purchased equip cost (B) 32,965

Direct Installation Costs 1,104,322

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 2,752,564

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 329,648

Construction & field expenses 20% of purchased equip cost (B) 329,648

Constractor fees 10% of purchased equip cost (B) 164,824

Start-up 1% of purchased equip cost (B) 16,482

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 32,965

Contingencies 3% of purchased equip cost (B) 49,447

Total Indirect Capital Costs 57% 923,015

Total Capital Investment (TCI) = DC + IC 3,675,579

OPERATING COSTS

Direct Operating Costs

Operator 25.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 25,000

Supervisor 15% of operator costs 3,750

Coordinator 33% of operator costs 8,250

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 18,093

Maintenance Materials 1% of purchased equipment costs 16,482

Utilities

Electricity 0.05 $/kW-hr, 262.4 kW-hr, 8000 hr/yr, 90.0% of capacity 96,571

Water NA - 

Solid Waste Disposal 25.00 $/Ton, 0.008 gr/dscf, 8000 hr/yr 1,018

Wastewater Treatment NA - 

Total Annual Direct Operating Costs, DC 169,165

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 37,995

Administration (2% total capital costs) 2% of total capital costs (TCI) 73,512

Property tax (1% total capital costs) 1% of total capital costs (TCI) 36,756

Insurance (1% total capital costs) 1% of total capital costs (TCI) 36,756

Captial Recovery 9% for a 20- year equipment life and a 7% interest rate 346,949

Total Indirect Operating Costs 531,967

Total Annual Cost (Annualized Capital Cost + Operating Cost) 701,132

Pollutant Removed (tons/yr)B 40.7

Cost per ton of PM Removed 17,214

Notes & Assumptions

1 EPA Cost Manual 6th Ed. 2002

2 Cost estimates based on 2001 ESP cost curve data. 

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - ESP Page 11 of 26
MPCA BART Anaylsis 2003

Table K-7: ESP - Straight Grate Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow dscfm 150,000 170455 scfm

135 Temp Deg F

12% % Moisture

 acfm 188,865

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 1 hr/8 hr shift 1,000 25,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft2

 collector 45,589 ft2 collector area 4,125 $/ft2 collector area; $5775 if < 50,000 ft 2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 262 kW-hr 2,099,368 96,571 $/kW-hr, 262.4 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0.0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.005 ton/hr 41 1,018 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.008 gr/dscf 150,000 dscfm NA 41.14

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 0.4 Currently assumes 99%.

Emission Reduction T/yr 40.7

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower Eff kW

Blower 188,865 5 0.65 170.0 OAQPS Cost Cont Manual 6th ed - Eq 3.46

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 NA 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 NA 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 45,589 88.4 2 4 92.4 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 150,000 acfm

Area #2 45589.0 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - ESP Page 12 of 26
MPCA BART Anaylsis 2003

Table K-8: ESP - Grate/Kiln Induration - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 2,217,727

Instrumentation 10% of control device cost (A) 221,773

MN Sales Taxes 3% of control device cost (A) 66,532

Freight 5% of control device cost (A) 110,886

Purchased Equipment Total (B) 18% 2,616,918

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 104,677

Handling & erection 50% of purchased equip cost (B) 1,308,459

Electrical 8% of purchased equip cost (B) 209,353

Piping 1% of purchased equip cost (B) 26,169

Insulation for ductwork 2% of purchased equip cost (B) 52,338

Painting 2% of purchased equip cost (B) 52,338

Direct Installation Costs 1,753,335

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 4,370,253

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 523,384

Construction & field expenses 20% of purchased equip cost (B) 523,384

Constractor fees 10% of purchased equip cost (B) 261,692

Start-up 1% of purchased equip cost (B) 26,169

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 52,338

Contingencies 3% of purchased equip cost (B) 78,508

Total Indirect Capital Costs 57% 1,465,474

Total Capital Investment (TCI) = DC + IC 5,835,727

OPERATING COSTS

Direct Operating Costs

Operator 25.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 25,000

Supervisor 15% of operator costs 3,750

Coordinator 33% of operator costs 8,250

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 32,708

Maintenance Materials 1% of purchased equipment costs 26,169

Utilities

Electricity 0.05 $/kW-hr, 520.8 kW-hr, 8000 hr/yr, 90.0% of capacity 191,670

Water NA - 

Solid Waste Disposal 25.00 $/Ton, 0.050 gr/dscf, 8000 hr/yr 12,729

Wastewater Treatment NA - 

Total Annual Direct Operating Costs, DC 300,276

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 52,576

Administration (2% total capital costs) 2% of total capital costs (TCI) 116,715

Property tax (1% total capital costs) 1% of total capital costs (TCI) 58,357

Insurance (1% total capital costs) 1% of total capital costs (TCI) 58,357

Captial Recovery 9% for a 20- year equipment life and a 7% interest rate 550,851

Total Indirect Operating Costs 836,857

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,137,133

Pollutant Removed (tons/yr)B 509.1

Cost per ton of PM Removed 2,233

Notes & Assumptions

1 EPA Cost Manual 6th Ed. 2002

2 Cost estimates based on 2001 ESP cost curve data. 

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate, Kiln - ESP Page 13 of 26
MPCA BART Anaylsis 2003

Table K-8: ESP - Grate/Kiln Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow dscfm 300,000 340909 scfm

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 1 hr/8 hr shift 1,000 25,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft2

 collector 91,178 ft2 collector area 10,531 $/ft2 collector area; $5775 if < 50,000 ft 2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 521 kW-hr 4,166,736 191,670 $/kW-hr, 520.8 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0.0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.064 ton/hr 509 12,729 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.05 gr/dscf 300,000 dscfm NA 514.29

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 5.1 Currently assumes 99%.

Emission Reduction T/yr 509.1

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower Eff kW

Blower 377,730 5 0.65 340.0 OAQPS Cost Cont Manual 6th ed - Eq 3.46

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 NA 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 NA 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 91,178 176.9 2 4 180.9 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 300,000 acfm

Area #2 91177.9 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate, Kiln - ESP Page 14 of 26
MPCA BART Anaylsis 2003

Table K-9: Wet Wall ESP - Straight Grate Induration - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 1,438,720

Instrumentation 10% of control device cost (A) 143,872

MN Sales Taxes 3% of control device cost (A) 43,162

Freight 5% of control device cost (A) 71,936

Purchased Equipment Total (B) 18% 1,697,690

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 67,908

Handling & erection 50% of purchased equip cost (B) 848,845

Electrical 8% of purchased equip cost (B) 135,815

Piping 1% of purchased equip cost (B) 16,977

Insulation for ductwork 2% of purchased equip cost (B) 33,954

Painting 2% of purchased equip cost (B) 33,954

Direct Installation Costs 1,137,452

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 2,835,142

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 339,538

Construction & field expenses 20% of purchased equip cost (B) 339,538

Constractor fees 10% of purchased equip cost (B) 169,769

Start-up 1% of purchased equip cost (B) 16,977

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 33,954

Contingencies 3% of purchased equip cost (B) 50,931

Total Indirect Capital Costs 57% 950,706

Total Capital Investment (TCI) = DC + IC 3,785,848

OPERATING COSTS

Direct Operating Costs

Operator 25.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 25,000

Supervisor 15% of operator costs 3,750

Coordinator 33% of operator costs 8,250

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 21,017

Maintenance Materials 1% of purchased equipment costs 16,977

Utilities

Electricity 0.05 $/kW-hr, 312.0 kW-hr, 8000 hr/yr, 90.0% of capacity 114,803

Water 0.22 $/Mgal, 1,699.8 gpm, 8000 hr/yr, 90.0% of capacity 179,497

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 1,699.8 gpm, 8000 hr/yr, 90.0% of capacity 1,223,845

Reagent (Caustic) 280.00 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Total Annual Direct Operating Costs, DC 1,593,139

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 40,046

Administration (2% total capital costs) 2% of total capital costs (TCI) 75,717

Property tax (1% total capital costs) 1% of total capital costs (TCI) 37,858

Insurance (1% total capital costs) 1% of total capital costs (TCI) 37,858

Captial Recovery 9% for a 20- year equipment life and a 7% interest rate 357,357

Total Indirect Operating Costs 548,838

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,141,976

Pollutant Removed (tons/yr)B 40.7

Cost per ton of PM Removed 52,588

Notes & Assumptions

1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 EPA Cost Manual 6th Ed. 2002

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - Wet ESP Page 15 of 26
MPCA BART Anaylsis 2003

Table K-9: Wet Wall ESP - Straight Grate Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

Amount Required 0 ft

3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow dscfm 150,000 170455 scfm

135 Temp Deg F

12% % Moisture

 acfm 188,865

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 1 hr/8 hr shift 1,000 25,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft

2

 collector 57,401 ft

2 collector area 6,630 $/ft2 collector area; $5775 if < 50,000 ft2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 312 kW-hr 2,495,722 114,803 $/kW-hr, 312.0 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 1700 gpm 815,896 179,497 $/Mgal, 1,699.8 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 1700 gpm 815,896 1,223,845 $/Mgal, 1,699.8 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft

3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.008 gr/dscf 150,000 dscfm NA 41.14

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 0.4 Currently assumes 99%.

Emission Reduction T/yr 40.7

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 188,865 5 0.65 170.0 OAQPS Cost Cont Manual 6th ed - Eq 3.46

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 1700 60 0.8 0.9 26.6 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 57,401 111.4 2 4 115.4 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 10.29 lb/hr SO2 2.50 lb NaOH/lb SO2 0.013 T/hr Caustic

Lime Use 10.29 lb/hr SO2 1.53 lb Lime/lb SO2 0.008 T/hr Lime

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 acfm 188,865

Area #2 57401.0 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - Wet ESP Page 16 of 26
MPCA BART Anaylsis 2003

Table K-10: Wet Wall ESP - Grate/Kiln Induration - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 2,284,259

Instrumentation 10% of control device cost (A) 228,426

MN Sales Taxes 3% of control device cost (A) 68,528

Freight 5% of control device cost (A) 114,213

Purchased Equipment Total (B) 18% 2,695,426

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 107,817

Handling & erection 50% of purchased equip cost (B) 1,347,713

Electrical 8% of purchased equip cost (B) 215,634

Piping 1% of purchased equip cost (B) 26,954

Insulation for ductwork 2% of purchased equip cost (B) 53,909

Painting 2% of purchased equip cost (B) 53,909

Direct Installation Costs 1,805,935

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 4,501,361

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 539,085

Construction & field expenses 20% of purchased equip cost (B) 539,085

Constractor fees 10% of purchased equip cost (B) 269,543

Start-up 1% of purchased equip cost (B) 26,954

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 53,909

Contingencies 3% of purchased equip cost (B) 80,863

Total Indirect Capital Costs 57% 1,509,438

Total Capital Investment (TCI) = DC + IC 6,010,799

OPERATING COSTS

Direct Operating Costs

Operator 25.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 25,000

Supervisor 15% of operator costs 3,750

Coordinator 33% of operator costs 8,250

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 36,102

Maintenance Materials 1% of purchased equipment costs 26,954

Utilities

Electricity 0.05 $/kW-hr, 619.9 kW-hr, 8000 hr/yr, 90.0% of capacity 228,134

Water 0.22 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity 358,994

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity 2,447,689

Reagent (Caustic) 280.00 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Total Annual Direct Operating Costs, DC 3,134,874

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 55,084

Administration (2% total capital costs) 2% of total capital costs (TCI) 120,216

Property tax (1% total capital costs) 1% of total capital costs (TCI) 60,108

Insurance (1% total capital costs) 1% of total capital costs (TCI) 60,108

Captial Recovery 9% for a 20- year equipment life and a 7% interest rate 567,377

Total Indirect Operating Costs, IC 862,893

Total Annual Cost (Annualized Capital Cost + Operating Cost) 3,997,767

Pollutant Removed (tons/yr)B 509.1

Cost per ton of PM Removed 7,852

Notes & Assumptions

1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 EPA Cost Manual 6th Ed. 2002

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate, Kiln - Wet ESP Page 17 of 26
MPCA BART Anaylsis 2003

Table K-10: Wet Wall ESP - Grate/Kiln Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

Amount Required 0 ft

3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow dscfm 300,000 340909 scfm

135 Temp Deg F

12% % Moisture

 acfm 377,730

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 1 hr/8 hr shift 1,000 25,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft

2

 collector 114,802 ft

2 collector area 13,260 $/ft2 collector area; $5775 if < 50,000 ft2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 620 kW-hr 4,959,444 228,134 $/kW-hr, 619.9 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 3400 gpm 1,631,793 358,994 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 3400 gpm 1,631,793 2,447,689 $/Mgal, 3,399.6 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft

3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.05 gr/dscf dscfm 300,000 NA 514.29

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 5.1 Currently assumes 99%.

Emission Reduction T/yr 509.1

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 377,730 5 0.65 340.0 OAQPS Cost Cont Manual 6th ed - Eq 3.46

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 3400 60 0.8 0.9 53.3 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 114,802 222.7 2 4 226.7 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 128.57 lb/hr SO2 2.50 lb NaOH/lb SO2 0.161 T/hr Caustic

Lime Use 128.57 lb/hr SO2 1.53 lb Lime/lb SO2 0.098 T/hr Lime

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 acfm 377,730

Area #2 114802.0 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate, Kiln - Wet ESP Page 18 of 26
MPCA BART Anaylsis 2003

Table K-11: Baghouse - Straight Grate Induration - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Fabric Filter (EC) + bags + auxillary equipment 831,004

Instrumentation 10% of control device cost (A) 83,100

MN Sales Taxes 3% of control device cost (A) 24,930

Freight 5% of control device cost (A) 41,550

Purchased Equipment Total (B) 18% 980,585

Direct installation costs

Foundations & supports 4% of purchased equip cost (B) 39,223

Handling & erection 50% of purchased equip cost (B) 490,292

Electrical 8% of purchased equip cost (B) 78,447

Piping 1% of purchased equip cost (B) 9,806

Insulation for ductwork 7% of purchased equip cost (B) 68,641

Painting 4% of purchased equip cost (B) 39,223

Installation Total 74% 725,633

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost 1,706,217

Indirect Capital Costs

Engineering 10% of purchased equip cost (B) 98,058

Construction and field expense 20% of purchased equip cost (B) 196,117

Contractor fees 10% of purchased equip cost (B) 98,058

Startup 1% of purchased equip cost (B) 9,806

Performance test 1% of purchased equip cost (B) 9,806

Contingencies 3% of purchased equip cost (B) 29,418

Total Indirect Capital Costs 45% 441,263

Total Capital Investment (TCI) = DC + IC 2,147,481

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 50,000

Supervisor 15% of operator labor costs 7,500

Maintenance Labor 17.50 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 17,500

Maintenance Materials 100% of maintenance labor costs 17,500

Replacement parts, bags 123,039

Utilities

 Electricity 0.05 $/kW-hr, 1,640.9 kW-hr, 8000 hr/yr, 90.0% of capacity 603,836

 Compressed Air 0.27 $/Mscf, 377.7 Mscfm, 8000 hr/yr, 90.0% of capacity 48,954

 Solid Waste Disposal 25.00 $/Ton, 0.008 gr/dscf, 8000 hr/yr 1,018

Total Annual Direct Operating Costs (DC) 869,347

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 55,500

Administration (2% total capital costs) 2% of total capital costs (TCI) 42,950

Property tax (1% total capital costs) 1% of total capital costs (TCI) 21,475

Insurance (1% total capital costs) 1% of total capital costs (TCI) 21,475

Capital Recovery 9% for a 20- year equipment life and a 7% interest rate 202,707

Total Indirect Operating Costs 344,106

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,213,453

Pollutant Removed (tons/yr)B 41

Cost per ton of PM Removed 29,792

Notes & Assumptions

1 1 EPA Cost Manual 6th Ed. 2002

2

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - Baghouse Page 19 of 26
MPCA BART Anaylsis 2003

Table K-11: Baghouse - Straight Grate Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 35 $ each

Amount Required 3,022 Number

Total Rep Parts Cost 114,225 Cost adjusted for freight & sales tax

Installation Labor 8,814 10 min per bag Labor at $17.50/hr

Total Installed Cost 123,039

Annualized Cost 68,052

Total Cost Replacement Parts (Bags) 123,039

Design Flow dscfm 150,000 170455 scfm

135 Temp Deg F

12% % Moisture

 acf 188,865 m

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 2 hr/8 hr shift 2,000 50,000 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.5 Hr 1 hr/8 hr shift 1,000 17,500 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1641 kW-hr 13,126,866 603,836 $/kW-hr, 1,640.9 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf Mscfm 377.73 181,310 48,954 $/Mscf, 377.7 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.005 ton/hr 41 1,018 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 35 bag 3021.838497 bags 2 yr life 68,052 $/bag, 3,021.8 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.008 gr/dscf 150,000 dscfm NA 41

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 0.4 Currently assumes 99%.

Emission Reduction T/yr 41 

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 188,865 6 0.65 1640.9 OAQPS Cost Cont Manual 6th ed - Eq 1.14

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - Baghouse Page 20 of 26
MPCA BART Anaylsis 2003

Table K-12: Baghouse - Grate/Kiln Induration - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Fabric Filter (EC) + bags + auxillary equipment 1,662,012

Instrumentation 10% of control device cost (A) 166,201

MN Sales Taxes 3% of control device cost (A) 49,860

Freight 5% of control device cost (A) 83,101

Purchased Equipment Total (B) 18% 1,961,174

Direct installation costs

Foundations & supports 4% of purchased equip cost (B) 78,447

Handling & erection 50% of purchased equip cost (B) 980,587

Electrical 8% of purchased equip cost (B) 156,894

Piping 1% of purchased equip cost (B) 19,612

Insulation for ductwork 7% of purchased equip cost (B) 137,282

Painting 4% of purchased equip cost (B) 78,447

Installation Total 74% 1,451,269

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost 3,412,443

Indirect Capital Costs

Engineering 10% of purchased equip cost (B) 196,117

Construction and field expense 20% of purchased equip cost (B) 392,235

Contractor fees 10% of purchased equip cost (B) 196,117

Startup 1% of purchased equip cost (B) 19,612

Performance test 1% of purchased equip cost (B) 19,612

Contingencies 3% of purchased equip cost (B) 58,835

Total Indirect Capital Costs 45% 882,528

Total Capital Investment (TCI) = DC + IC 4,294,971

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 50,000

Supervisor 15% of operator labor costs 7,500

Maintenance Labor 17.50 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 17,500

Maintenance Materials 100% of maintenance labor costs 17,500

Replacement parts, bags 246,078

Utilities

 Electricity 0.05 $/kW-hr, 3,281.7 kW-hr, 8000 hr/yr, 90.0% of capacity 1,207,672

 Compressed Air 0.27 $/Mscf, 755.5 Mscfm, 8000 hr/yr, 90.0% of capacity 97,908

 Solid Waste Disposal 25.00 $/Ton, 0.050 gr/dscf, 8000 hr/yr 12,729

Total Annual Direct Operating Costs (DC) 1,656,886

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 55,500

Administration (2% total capital costs) 2% of total capital costs (TCI) 85,899

Property tax (1% total capital costs) 1% of total capital costs (TCI) 42,950

Insurance (1% total capital costs) 1% of total capital costs (TCI) 42,950

Capital Recovery 9% for a 20- year equipment life and a 7% interest rate 405,415

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 632,714

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,289,600

Pollutant Removed (tons/yr)B 509

Cost per ton of PM Removed 4,497

Notes & Assumptions

1 1 EPA Cost Manual 6th Ed. 2002

2

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate, Kiln - Baghouse Page 21 of 26
MPCA BART Anaylsis 2003

Table K-12: Baghouse - Grate/Kiln Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 35 $ each

Amount Required 6043.67699 Number

Total Rep Parts Cost 228,451 Cost adjusted for freight & sales tax

Installation Labor 17,627 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 246,078

Annualized Cost 136,104

Total Cost Replacement Parts (Bags) 246,078

Design Flow 300,000 dscfm 340909 scfm

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 2 hr/8 hr shift 2,000 50,000 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.5 Hr 1 hr/8 hr shift 1,000 17,500 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 3282 kW-hr 26,253,733 1,207,672 $/kW-hr, 3,281.7 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 755.46 Mscfm 362,621 97,908 $/Mscf, 755.5 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.064 ton/hr 509 12,729 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 35 bag 6043.67699 bags 2 yr life 136,104 $/bag, 6,043.7 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.05 gr/dscf 300,000 dscfm NA 514

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 5.1 Currently assumes 99%.

Emission Reduction T/yr 509

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 377,730 6 0.65 3281.7 OAQPS Cost Cont Manual 6th ed - Eq 1.14

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate, Kiln - Baghouse Page 22 of 26
MPCA BART Anaylsis 2003

Table K-13: Multiclone - Straight Grate Induration - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Fabric Filter (EC) + bags + auxillary equipment 116,000

Instrumentation 10% of control device cost (A) 11,600

MN Sales Taxes 3% of control device cost (A) 3,480

Freight 5% of control device cost (A) 5,800

Purchased Equipment Total (B) 18% 136,880

Direct installation costs

Foundations & supports 4% of purchased equip cost (B) 5,475

Handling & erection 40% of purchased equip cost (B) 54,752

Electrical 8% of purchased equip cost (B) 10,950

Piping 1% of purchased equip cost (B) 1,369

Insulation for ductwork 7% of purchased equip cost (B) 9,582

Painting 4% of purchased equip cost (B) 5,475

Installation Total 74% 87,603

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost 224,483

Indirect Capital Costs

Engineering 10% of purchased equip cost (B) 13,688

Construction and field expense 10% of purchased equip cost (B) 13,688

Contractor fees 10% of purchased equip cost (B) 13,688

Startup 1% of purchased equip cost (B) 1,369

Performance test 1% of purchased equip cost (B) 1,369

Contingencies 3% of purchased equip cost (B) 4,106

Total Indirect Capital Costs 45% 47,908

Total Capital Investment (TCI) = DC + IC 272,391

OPERATING COSTS

Direct Operating Costs

Operating Labor 17.26 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,630

Supervisor 15% of operator labor costs 1,295

Maintenance Labor 17.74 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,870

Maintenance Materials 100% of maintenance labor costs 8,870

Replacement parts, bags 0

Utilities

 Electricity 0.05 $/kW-hr, 1,640.9 kW-hr, 8000 hr/yr, 90.0% of capacity 603,836

 Compressed Air NA - 

 Solid Waste Disposal 25.00 $/Ton, 0.008 gr/dscf, 8000 hr/yr 823

Total Annual Direct Operating Costs (DC) 632,323

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 16,599

Administration (2% total capital costs) 2% of total capital costs (TCI) 5,448

Property tax (1% total capital costs) 1% of total capital costs (TCI) 2,724

Insurance (1% total capital costs) 1% of total capital costs (TCI) 2,724

Capital Recovery 9% for a 20- year equipment life and a 7% interest rate 25,712

Total Indirect Operating Costs 53,206

Total Annual Cost (Annualized Capital Cost + Operating Cost) 685,529

Pollutant Removed (tons/yr)B 33

Cost per ton of PM Removed 20,828

Notes & Assumptions

1 1 EPA Cost Manual 6th Ed. 2002

2 Equipment cost estimates provided by Allen-Sherman-Hoff, July 2003.

3 Equipment cost estimated using 0.6 Power factor in conjunction with multiclone quote provided by Allen-Sherman-Hoff. 

4 Reduced erection to 40% and Const Field Exp to 10% to address simpler installation.

5 Reduced operator and maintenance hours to address simpler operation.

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - Multiclone Page 23 of 26
MPCA BART Anaylsis 2003

Table K-13: Multiclone - Straight Grate Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 150,000 dscfm 170455 scfm

135 Temp Deg F

12% % Moisture

188,865 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 17.26 Hr 0.5 hr/8 hr shift 500 8,630 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.74 Hr 0.5 hr/8 hr shift 500 8,870 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 1641 kW-hr 13,126,866 603,836 $/kW-hr, 1,640.9 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.004 ton/hr 33 823 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.008 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.008 gr/dscf 150,000 dscfm NA 41

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

80% 8 Currently assumes 80%.

Emission Reduction T/yr 33 

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 188,865 6 0.65 1640.9 OAQPS Cost Cont Manual 6th ed - Eq 1.14

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls St Grate - Multiclone Page 24 of 26
MPCA BART Anaylsis 2003

Table K-14: Multiclone - Grate/Kiln Induration - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Fabric Filter (EC) + bags + auxillary equipment 227,000

Instrumentation 10% of control device cost (A) 22,700

MN Sales Taxes 3% of control device cost (A) 6,810

Freight 5% of control device cost (A) 11,350

Purchased Equipment Total (B) 18% 267,860

Direct installation costs

Foundations & supports 4% of purchased equip cost (B) 10,714

Handling & erection 40% of purchased equip cost (B) 107,144

Electrical 8% of purchased equip cost (B) 21,429

Piping 1% of purchased equip cost (B) 2,679

Insulation for ductwork 7% of purchased equip cost (B) 18,750

Painting 4% of purchased equip cost (B) 10,714

Installation Total 74% 171,430

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost 439,290

Indirect Capital Costs

Engineering 10% of purchased equip cost (B) 26,786

Construction and field expense 10% of purchased equip cost (B) 26,786

Contractor fees 10% of purchased equip cost (B) 26,786

Startup 1% of purchased equip cost (B) 2,679

Performance test 1% of purchased equip cost (B) 2,679

Contingencies 3% of purchased equip cost (B) 8,036

Total Indirect Capital Costs 45% 93,751

Total Capital Investment (TCI) = DC + IC 533,041

OPERATING COSTS

Direct Operating Costs

Operating Labor 17.26 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,630

Supervisor 15% of operator labor costs 1,295

Maintenance Labor 17.74 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,870

Maintenance Materials 100% of maintenance labor costs 8,870

Replacement parts, bags 0

Utilities

 Electricity 0.05 $/kW-hr, 3,281.7 kW-hr, 8000 hr/yr, 90.0% of capacity 1,207,672

 Compressed Air NA - 

 Solid Waste Disposal 25.00 $/Ton, 0.050 gr/dscf, 8000 hr/yr 10,286

Total Annual Direct Operating Costs (DC) 1,245,622

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 16,599

Administration (2% total capital costs) 2% of total capital costs (TCI) 10,661

Property tax (1% total capital costs) 1% of total capital costs (TCI) 5,330

Insurance (1% total capital costs) 1% of total capital costs (TCI) 5,330

Capital Recovery 9% for a 20- year equipment life and a 7% interest rate 50,315

Total Indirect Operating Costs Sum indirect oper costs + capital recovery cost 88,236

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,333,858

Pollutant Removed (tons/yr)B 411

Cost per ton of PM Removed 3,242

Notes & Assumptions

1 1 EPA Cost Manual 6th Ed. 2002

2 Equipment cost estimates provided by Allen-Sherman-Hoff, July 2003.

3 Equipment cost estimated using 0.6 Power factor in conjunction with multiclone quote provided by Allen-Sherman-Hoff. 

4 Reduced erection to 40% and Const Field Exp to 10% to address simpler installation.

5 Reduced operator and maintenance hours to address simpler operation.

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate,Kiln - Multiclone Page 25 of 26
MPCA BART Anaylsis 2003

Table K-14: Multiclone - Grate/Kiln Induration - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 300,000 dscfm 340909 scfm

135 Temp Deg F

12% % Moisture

377,730 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 17.26 Hr 0.5 hr/8 hr shift 500 8,630 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.74 Hr 0.5 hr/8 hr shift 500 8,870 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 3282 kW-hr 26,253,733 1,207,672 $/kW-hr, 3,281.7 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.051 ton/hr 411 10,286 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.050 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.05 gr/dscf 300,000 dscfm NA 514

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

80% 103 Currently assumes 80%.

Emission Reduction T/yr 411 

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 377,730 6 0.65 3281.7 OAQPS Cost Cont Manual 6th ed - Eq 1.14

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment K.xls Grate,Kiln - Multiclone Page 26 of 26
ATTACHMENT L 

Model BART Cost Analysis - Pellet Coolers PM Emissions 

List of Tables: 

Table L-1: BART Screening Evaluation Summary: Pellet Cooler - Wet Scrubber, ESP, Wet Wall ESP, 

Fabric Filters and Multiclones 

Table L-2: Low Efficiency Wet Scrubber - Pellet Cooler - PM 

Table L-3: High Efficiency Wet Scrubber - Pellet Cooler - PM 

Table L-4: ESP - Pellet Cooler - PM 

Table L-5: Wet Wall ESP - Pellet Cooler - PM 

Table L-6: Baghouse - Pellet Cooler - PM 

Table L-7: Multiclone - Pellet Cooler - PM 
MPCA BART Analysis 2003

Table L-1: BART Screening Evaluation Summary: Pellet Cooler - Wet Scrubber, ESP, Wet Wall ESP, 

Multiclones

Model Source for Pellet Cooler Exhaust PM Emissions

General InformationSource Type Pellet Cooler ExhaustPollutant: Particulate Matter (PM10)Existing Pollution 

Control Equipment Most sources are routed to a wet scrubberControl Cost SummaryControl Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed 

Capital Cost $

Annualized 

Operating 

Cost $/yr

Pollution 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Wet Scrubbers High 

Efficiency 99% 1028.6 1018.3 662,420 1,344,887 1,321 None Medium 

Wet Scrubbers Low 

Efficiency 92% 1028.6 946.3 662,420 1,344,887 1,421 None Medium 

Dry ElectroStatic 

Precipitators (ESP) 99% 1028.6 1018.3 4,004,917 792,842 779 None Low 

Wet Wall ElectroStatic 

Precipitator (WWESP) 99% 1028.6 1018.3 4,125,064 2,572,757 2,527 None Low 

Fabric Filters 

(Baghouses) 99% 1028.6 1018.3 2,474,888 1,635,560 1,606 None High 

Multiclones 80% 1028.6 822.9 455,957 898,336 1,092 None High 

Comments

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Pellet Cooler Summary 
MPCA BART Analysis 2003

Table L-2: Low Efficiency Wet Scrubber - Pellet Cooler - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 247,819

Instrumentation 10% of control device cost (A) 24,782

MN Sales Taxes 6.5% of control device cost (A) 16,108

Freight 5% of control device cost (A) 12,391

Purchased Equipment Total (B) 22% 301,100

Installation

Foundations & supports 12% of purchased equip cost (B) 36,132

Handling & erection 40% of purchased equip cost (B) 120,440

Electrical 1% of purchased equip cost (B) 3,011

Piping 30% of purchased equip cost (B) 90,330

Insulation 1% of purchased equip cost (B) 3,011

Painting 1% of purchased equip cost (B) 3,011

Installation Total 85% 255,935

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 557,035

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 30,110

Construction & field expenses 10% of purchased equip cost (B) 30,110

Construction fee 10% of purchased equip cost (B) 30,110

Start-up 1% of purchased equip cost (B) 3,011

Performance test 1% of purchased equip cost (B) 3,011

Contingencies 3% of purchased equip cost (B) 9,033

Total Indirect Capital Costs, IC 35% 105,385

Total Capital Investment (TCI) = DC + IC 662,420

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Reagent #2 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 431.0 gpm, 8000 hr/yr, 90.0% of capacity 279,266

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 885 kW-hr, 8000 hr/yr, 90.0% of capacity 293,204

Total Annual Direct Operating Costs 602,907

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 13,248

Property tax (1% total capital costs) 1% of total capital costs (TCI) 6,624

Insurance (1% total capital costs) 1% of total capital costs (TCI) 6,624

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 94,314 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 741,980

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,344,887

Pollutant Removed (tons/yr)B 946

Cost per ton of PM Removed 1,421

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - Low Scrub Page 2 of 13
MPCA BART Analysis 2003

Table L-2: Low Efficiency Wet Scrubber - Pellet Cooler - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

Amount Required 0 ft

3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 100,000 dscfm 102041 scfm

800 Temp Deg F

2% % Moisture

 acfm 239,425

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 885 kW-hr 6,373,994 293,204 $/kW-hr, 885 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 431.0 gpm 186,177 40,959 $/Mgal, 431.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 431.0 gpm 186,177 279,266 $/Mgal, 431.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft

3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost facto

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 100,000 dscfm NA 1,028.6 Assuming 92% control (range is 90-95%).

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

92% 82 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 946.3

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 215,483 12 0.55 0.7 785.8 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm D P ft H2O Pump Eff Motor Eff

Circ Pump 2,155 125 0.8 0.7 90.4 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 431.0 62.5 0.8 0.7 9.0 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 20.57 lb/hr SO2 2.50 lb NaOH/lb SO2 51.43 lb/hr Caustic

Lime Use 20.57 lb/hr SO2 1.53 lb Lime/lb SO2 31.47 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - Low Scrub Page 3 of 13
MPCA BART Analysis 2003

Table L-3: High Efficiency Wet Scrubber - Pellet Cooler - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 247,819

Instrumentation 10% of control device cost (A) 24,782

MN Sales Taxes 6.5% of control device cost (A) 16,108

Freight 5% of control device cost (A) 12,391

Purchased Equipment Total (B) 22% 301,100

Installation

Foundations & supports 12% of purchased equip cost (B) 36,132

Handling & erection 40% of purchased equip cost (B) 120,440

Electrical 1% of purchased equip cost (B) 3,011

Piping 30% of purchased equip cost (B) 90,330

Insulation 1% of purchased equip cost (B) 3,011

Painting 1% of purchased equip cost (B) 3,011

Installation Total 85% 255,935

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 557,035

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 30,110

Construction & field expenses 10% of purchased equip cost (B) 30,110

Construction fee 10% of purchased equip cost (B) 30,110

Start-up 1% of purchased equip cost (B) 3,011

Performance test 1% of purchased equip cost (B) 3,011

Contingencies 3% of purchased equip cost (B) 9,033

Total Indirect Capital Costs, IC 35% 105,385

Total Capital Investment (TCI) = DC + IC 662,420

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Reagent #2 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 431.0 gpm, 8000 hr/yr, 90.0% of capacity 279,266

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 885 kW-hr, 8000 hr/yr, 90.0% of capacity 293,204

Total Annual Direct Operating Costs 602,907

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 13,248

Property tax (1% total capital costs) 1% of total capital costs (TCI) 6,624

Insurance (1% total capital costs) 1% of total capital costs (TCI) 6,624

Capital Recovery 14.24% for a 10- year equipment life and a 7% interest rate 94,314 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 741,980

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,344,887

Pollutant Removed (tons/yr)B 1,018

Cost per ton of PM Removed 1,321

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - High Scrub Page 4 of 13
MPCA BART Analysis 2003

Table L-3: High Efficiency Wet Scrubber - Pellet Cooler - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

Amount Required 0 ft

3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 100,000 dscfm 102041 scfm

800 Temp Deg F

2% % Moisture

 acfm 239,425

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 885 kW-hr 6,373,994 293,204 $/kW-hr, 885 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 431.0 gpm 186,177 40,959 $/Mgal, 431.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 431.0 gpm 186,177 279,266 $/Mgal, 431.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft

3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost facto

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 100,000 dscfm NA 1,028.6 Assuming 99% control.

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 10 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 1018.3

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 215,483 12 0.55 0.7 785.8 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm D P ft H2O Pump Eff Motor Eff

Circ Pump 2,155 125 0.8 0.7 90.4 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 431.0 62.5 0.8 0.7 9.0 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 2.57 lb/hr SO2 2.50 lb NaOH/lb SO2 6.43 lb/hr Caustic

Lime Use 2.57 lb/hr SO2 1.53 lb Lime/lb SO2 3.93 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - High Scrub Page 5 of 13
MPCA BART Analysis 2003

Table L-4: ESP - Pellet Cooler - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 1,521,972

Instrumentation 10% of control device cost (A) 152,197

MN Sales Taxes 3% of control device cost (A) 45,659

Freight 5% of control device cost (A) 76,099

Purchased Equipment Total (B) 18% 1,795,927

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 71,837

Handling & erection 50% of purchased equip cost (B) 897,963

Electrical 8% of purchased equip cost (B) 143,674

Piping 1% of purchased equip cost (B) 17,959

Insulation for ductwork 2% of purchased equip cost (B) 35,919

Painting 2% of purchased equip cost (B) 35,919

Direct Installation Costs 1,203,271

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 2,999,198

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 359,185

Construction & field expenses 20% of purchased equip cost (B) 359,185

Constractor fees 10% of purchased equip cost (B) 179,593

Start-up 1% of purchased equip cost (B) 17,959

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 35,919

Contingencies 3% of purchased equip cost (B) 53,878

Total Indirect Capital Costs 57% 1,005,719

Total Capital Investment (TCI) = DC + IC 4,004,917

OPERATING COSTS

Direct Operating Costs

Operator 25.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 25,000

Supervisor 15% of operator costs 3,750

Coordinator 33% of operator costs 8,250

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 8,405

Maintenance Materials 1% of purchased equipment costs 17,959

Utilities

Electricity 0.05 $/kW-hr, 361 kW-hr, 8000 hr/yr, 90.0% of capacity 132,720

Water NA - 

Solid Waste Disposal 25.00 $/Ton, 0.300 gr/dscf, 8000 hr/yr 25,457

Wastewater Treatment NA - 

Total Annual Direct Operating Costs, DC 221,541

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 33,068

Administration (2% total capital costs) 2% of total capital costs (TCI) 80,098

Property tax (1% total capital costs) 1% of total capital costs (TCI) 40,049

Insurance (1% total capital costs) 1% of total capital costs (TCI) 40,049

Captial Recovery 9% for a 20- year equipment life and a 7% interest rate 378,036

Total Indirect Operating Costs 571,301

Total Annual Cost (Annualized Capital Cost + Operating Cost) 792,842

Pollutant Removed (tons/yr)B 1,018.3

Cost per ton of PM Removed 779

Notes & Assumptions

1 1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - ESP Page 6 of 13
MPCA BART Analysis 2003

Table L-4: ESP - Pellet Cooler - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

Amount Required 0 ft

3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 100,000 dscfm 102041 scfm

800 Temp Deg F

2% % Moisture

239,425 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 1 hr/8 hr shift 1,000 25,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft

2

 collector 72,768 ft

2

 collector area 8,405 $/ft

2 collector area; $5775 if < 50,000 ft2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 361 kW-hr 2,885,217 132,720 $/kW-hr, 361 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 300 Ton 0.0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.127 ton/hr 1,018 25,457 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft

3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 100,000 dscfm NA 1028.57

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 10 Currently assumes 99%.

Emission Reduction T/yr 1018.3

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower Eff kW

Blower 239,425 5 0.65 215.5 OAQPS Cost Cont Manual 6th ed - Eq 3.46

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 NA 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 NA 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 72,768 141.2 2 4 145.2 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 239,425 acfm

Area #2 72768 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - ESP Page 7 of 13
MPCA BART Analysis 2003

Table L-5: Wet Wall ESP - Pellet Cooler - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 1,567,631

Instrumentation 10% of control device cost (A) 156,763

MN Sales Taxes 3% of control device cost (A) 47,029

Freight 5% of control device cost (A) 78,382

Purchased Equipment Total (B) 18% 1,849,805

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 73,992

Handling & erection 50% of purchased equip cost (B) 924,902

Electrical 8% of purchased equip cost (B) 147,984

Piping 1% of purchased equip cost (B) 18,498

Insulation for ductwork 2% of purchased equip cost (B) 36,996

Painting 2% of purchased equip cost (B) 36,996

Direct Installation Costs 1,239,369

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 3,089,174

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 369,961

Construction & field expenses 20% of purchased equip cost (B) 369,961

Constractor fees 10% of purchased equip cost (B) 184,980

Start-up 1% of purchased equip cost (B) 18,498

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 36,996

Contingencies 3% of purchased equip cost (B) 55,494

Total Indirect Capital Costs 57% 1,035,891

Total Capital Investment (TCI) = DC + IC 4,125,064

OPERATING COSTS

Direct Operating Costs

Operator 12.00 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,000

Supervisor 15% of operator costs 1,800

Coordinator 33% of operator costs 3,960

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 8,405

Maintenance Materials 1% of purchased equipment costs 18,498

Utilities

Electricity 0.05 $/kW-hr, 462 kW-hr, 8000 hr/yr, 90.0% of capacity 169,973

Water 0.22 $/Mgal, 2,154.8 gpm, 8000 hr/yr, 90.0% of capacity 227,550

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 2,154.8 gpm, 8000 hr/yr, 90.0% of capacity 1,551,476

Reagent (Caustic) 280.00 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH 294

Total Annual Direct Operating Costs, DC 1,993,956

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 24,422

Administration (2% total capital costs) 2% of total capital costs (TCI) 82,501

Property tax (1% total capital costs) 1% of total capital costs (TCI) 41,251

Insurance (1% total capital costs) 1% of total capital costs (TCI) 41,251

Captial Recovery 9% for a 20- year equipment life and a 7% interest rate 389,377

Total Indirect Operating Costs 578,801

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,572,757

Pollutant Removed (tons/yr)B 1,018.3

Cost per ton of PM Removed 2,527

Notes & Assumptions

1 1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 EPA Cost Manual 6th Ed. 2002

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - Wet ESP Page 8 of 13
MPCA BART Analysis 2003

Table L-5: Wet Wall ESP - Pellet Cooler - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

Amount Required 0 ft

3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 100,000 dscfm 102041 scfm

800 Temp Deg F

2% % Moisture

239,425 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 12 Hr 1 hr/8 hr shift 1,000 12,000 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft

2

 collector 72,768 ft

2 collector area 8,405 $/ft2 collector area; $5775 if < 50,000 ft2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 462 kW-hr 3,695,073 169,973 $/kW-hr, 462 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 2155 gpm 1,034,318 227,550 $/Mgal, 2,154.8 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0.003 lb-mole/hr 1 294 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 2155 gpm 1,034,318 1,551,476 $/Mgal, 2,154.8 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft

3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 100,000 dscfm NA 1028.57

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 10 Currently assumes 99%.

Emission Reduction T/yr 1018.3

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 239,425 5 0.55 0.9 283.0 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 2155 60 0.8 0.9 33.8 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 72,768 141.2 2 4 145.2 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 2.57 lb/hr SO2 2.50 lb NaOH/lb SO2 0.003 T/hr Caustic

Lime Use 2.57 lb/hr SO2 1.53 lb Lime/lb SO2 0.002 T/hr Lime

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 239,425 acfm

Area #2 72768 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - Wet ESP Page 9 of 13
MPCA BART Analysis 2003

Table L-6: Baghouse - Pellet Cooler - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Fabric Filter (EC) + bags + auxillary equipment 957,700

Instrumentation 10% of control device cost (A) 95,770

MN Sales Taxes 3% of control device cost (A) 28,731

Freight 5% of control device cost (A) 47,885

Purchased Equipment Total (B) 18% 1,130,086

Direct installation costs

Foundations & supports 4% of purchased equip cost (B) 45,203

Handling & erection 50% of purchased equip cost (B) 565,043

Electrical 8% of purchased equip cost (B) 90,407

Piping 1% of purchased equip cost (B) 11,301

Insulation for ductwork 7% of purchased equip cost (B) 79,106

Painting 4% of purchased equip cost (B) 45,203

Installation Total 74% 836,264

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost 1,966,350

Indirect Capital Costs

Engineering 10% of purchased equip cost (B) 113,009

Construction and field expense 20% of purchased equip cost (B) 226,017

Contractor fees 10% of purchased equip cost (B) 113,009

Startup 1% of purchased equip cost (B) 11,301

Performance test 1% of purchased equip cost (B) 11,301

Contingencies 3% of purchased equip cost (B) 33,903

Total Indirect Capital Costs 45% 508,539

Total Capital Investment (TCI) = DC + IC 2,474,888

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 50,000

Supervisor 15% of operator labor costs 7,500

Maintenance Labor 17.50 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 17,500

Maintenance Materials 100% of maintenance labor costs 17,500

Replacement parts, bags 155,978

Utilities

 Electricity 0.05 $/kW-hr, 2,080 kW-hr, 8000 hr/yr, 90.0% of capacity 765,487

 Compressed Air 0.27 $/mscf, 100 scfm, 8640 hr/yr 62,059

 Solid Waste Disposal 25.00 $/Ton, 0.300 gr/dscf, 8000 hr/yr 171,429

Total Annual Direct Operating Costs (DC) 1,247,452

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 55,500

Administration (2% total capital costs) 2% of total capital costs (TCI) 49,498

Property tax (1% total capital costs) 1% of total capital costs (TCI) 24,749

Insurance (1% total capital costs) 1% of total capital costs (TCI) 24,749

Capital Recovery 9% for a 20- year equipment life and a 7% interest rate 233,612

Total Indirect Operating Costs 388,107

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,635,560

Pollutant Removed (tons/yr)B 1,018

Cost per ton of PM Removed 1,606

Notes & Assumptions

1 1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - Baghouse Page 10 of 13
MPCA BART Analysis 2003

Table L-6: Baghouse - Pellet Cooler - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 35 $ each

Amount Required 3,831 Number

Total Rep Parts Cost 144,804 Cost adjusted for freight & sales tax

Installation Labor 11,173 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 155,978

Annualized Cost 86,270

Total Cost Replacement Parts (Bags) 155,978

Design Flow 100,000 dscfm 102041 scfm

800 Temp Deg F

2% % Moisture

239,425 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 2 hr/8 hr shift 2,000 50,000 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.5 Hr 1 hr/8 hr shift 1,000 17,500 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 2080 kW-hr 16,641,022 765,487 $/kW-hr, 2,080 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/mscf, 40 scfm, 8000 hr/yr

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 7.16 gpm; 8000 hr/yr

Comp Air 0.27 Mscf Mscfm 478.85 229,848 62,059 $/mscf, 100 scfm, 8640 hr/yr

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/T, 62 lb/lbmole, 0.76wt% NaOH, 8000 hr/yr

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/T, 62 lb/lbmole, 0.76wt% NaOH, 8000 hr/yr

SW Disposal 25 Ton 0.857 ton/hr 6,857 171,429 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 7.16 gpm; 8000 hr/yr

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 39 ft3 of catalyst, 2 yr cat life

Rep Parts 35 bag 3830.806065 bags 2 yr life 86,270 795 bags, 2 yr life

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 100,000 dscfm NA 1029

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 10 Currently assumes 99%.

Emission Reduction T/yr 1,018 

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 239,425 6 0.65 2080 OAQPS Cost Cont Manual 6th ed - Eq 1.14

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - Baghouse Page 11 of 13
MPCA BART Analysis 2003

Table L-7: Multiclone - Pellet Cooler - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Equipment 194,173

Instrumentation 10% of control device cost (A) 19,417

MN Sales Taxes 3% of control device cost (A) 5,825

Freight 5% of control device cost (A) 9,709

Purchased Equipment Total (B) 18% 229,124

Direct installation costs

Foundations & supports 4% of purchased equip cost (B) 9,165

Handling & erection 40% of purchased equip cost (B) 91,650

Electrical 8% of purchased equip cost (B) 18,330

Piping 1% of purchased equip cost (B) 2,291

Insulation for ductwork 7% of purchased equip cost (B) 16,039

Painting 4% of purchased equip cost (B) 9,165

Installation Total 74% 146,639

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost 375,764

Indirect Capital Costs

Engineering 10% of purchased equip cost (B) 22,912

Construction and field expense 10% of purchased equip cost (B) 22,912

Contractor fees 10% of purchased equip cost (B) 22,912

Startup 1% of purchased equip cost (B) 2,291

Performance test 1% of purchased equip cost (B) 2,291

Contingencies 3% of purchased equip cost (B) 6,874

Total Indirect Capital Costs 45% 80,193

Total Capital Investment (TCI) = DC + IC 455,957

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of operator labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Replacement parts, bags 0

Utilities

 Electricity 0.05 $/kW-hr, 2,080 kW-hr, 8000 hr/yr, 90.0% of capacity 765,487

 Compressed Air NA - 

 Solid Waste Disposal 25.00 $/Ton, 0.300 gr/dscf, 8000 hr/yr 20,571

Total Annual Direct Operating Costs (DC) 817,933

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Administration (2% total capital costs) 2% of total capital costs (TCI) 9,119

Property tax (1% total capital costs) 1% of total capital costs (TCI) 4,560

Insurance (1% total capital costs) 1% of total capital costs (TCI) 4,560

Capital Recovery 9% for a 20- year equipment life and a 7% interest rate 43,039

Total Indirect Operating Costs 80,402

Total Annual Cost (Annualized Capital Cost + Operating Cost) 898,336

Pollutant Removed (tons/yr)B 823

Cost per ton of PM Removed 1,092

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002. Assumed same cost factors as baghouse.

2 Equipment cost estimated using 0.6 Power factor in conjunction with multiclone quote provided by Allen-Sherman-Hoff. 

3 Reduced erection to 40% and Const Field Exp to 10% to address simpler installation.

4 Reduced operator and maintenance hours to address simpler operation.

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - Multiclone Page 12 of 13
MPCA BART Analysis 2003

Table L-7: Multiclone - Pellet Cooler - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts (Bags) 0

Design Flow 100,000 dscfm 102041 scfm

800 Temp Deg F

2% % Moisture

239,425 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 2080 kW-hr 16,641,022 765,487 $/kW-hr, 2,080 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf - Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.103 ton/hr 823 20,571 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 100,000 dscfm NA 1029

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

80% 206 Currently assumes 80%.

Emission Reduction T/yr 823 

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 239,425 6 0.65 2080 OAQPS Cost Cont Manual 6th ed - Eq 1.14

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment L.xls Cooler - Multiclone Page 13 of 13
ATTACHMENT M 

Model BART Cost Analysis - Iron Ore Material Handling PM Emissions 

List of Tables: 

Table M-1: BART Screening Evaluation Summary: Material Handling - Wet Scrubber, ESP, Wet Wall 

ESP, Fabric Filters, Multiclones and Enclosures 

Table M-2: Low Efficiency Wet Scrubber - Material Handling - PM 

Table M-3: High Efficiency Wet Scrubber - Material Handling - PM 

Table M-4: ESP - Material Handling - PM 

Table M-5: Wet Wall ESP - Material Handling - PM 

Table M-6: Baghouse - Material Handling - PM 

Table M-7: Multiclone - Material Handling - PM 

Table M-8: Enclosure - Material Handling - PM 
MPCA BART Analysis 2003

Table M-1: BART Screening Evaluation Summary: Material Handling - Wet Scrubber, ESP, Wet Wall 

Multiclones and Enclosures

Model Source for Iron Ore Material Handling - PM Emissions from Conveyor Drops

General InformationSource Type Iron Ore Material Handling - Conveyor DropsPollutant: Particulate Matter (PM10)Existing Pollution Control Equipment Most sources are routed to a wet scrubberControl Cost SummaryControl Technology

Control 

Eff %

Emissions 

T/y

Emission 

Reduction 

T/yr

Installed 

Capital Cost $

Annualized 

Operating 

Cost $/yr

Pollution 

Control Cost 

$/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Wet Scrubbers High 

Efficiency 99% 11.7 11.6 127,932 136,627 11,795 None High 

Wet Scrubbers Low 

Efficiency 92% 11.7 10.8 126,283 136,326 12,665 None High 

Dry ElectroStatic 

Precipitators (ESP) 99% 11.7 11.6 1,644,512 301,977 26,071 None Medium 

Wet Wall ElectroStatic 

Precipitator (WWESP) 99% 11.7 11.6 1,693,848 334,648 28,891 None Medium 

Fabric Filters 

(Baghouses) 99% 11.7 11.6 83,625 189,010 16,318 None Low 

Multiclones* 80% 11.7 9.4 21,459 31,055 3,318 None Low 

Enclosure NA 11.7 11.3 55,611 51,977 4,586 None None 

* Control costs based on connecting 10 sources together; a single source was too small for the vendor to provide a cost estimate. Values foremissions, emissions reduction, installed capital cost and annualized operating cost are 1/10 of the values listed in Table M-7 to account for this issue

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls Mtl Hand Summary 
MPCA BART Analysis 2003

Table M-2: Low Efficiency Wet Scrubber - Material Handling - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 47,244

Instrumentation 10% of control device cost (A) 4,724

MN Sales Taxes 6.5% of control device cost (A) 3,071

Freight 5% of control device cost (A) 2,362

Purchased Equipment Total (B) 22% 57,401

Installation

Foundations & supports 12% of purchased equip cost (B) 6,888

Handling & erection 40% of purchased equip cost (B) 22,961

Electrical 1% of purchased equip cost (B) 574

Piping 30% of purchased equip cost (B) 17,220

Insulation 1% of purchased equip cost (B) 574

Painting 1% of purchased equip cost (B) 574

Installation Total 85% 48,791

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 106,193

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 5,740

Construction & field expenses 10% of purchased equip cost (B) 5,740

Construction fee 10% of purchased equip cost (B) 5,740

Start-up 1% of purchased equip cost (B) 574

Performance test 1% of purchased equip cost (B) 574

Contingencies 3% of purchased equip cost (B) 1,722

Total Indirect Capital Costs, IC 35% 20,091

Total Capital Investment (TCI) = DC + IC 126,283

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Reagent #2 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 12.9 gpm, 8000 hr/yr, 90.0% of capacity 8,331

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 26 kW-hr, 8000 hr/yr, 90.0% of capacity 8,747

Total Annual Direct Operating Costs 47,516

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 2,526

Property tax (1% total capital costs) 1% of total capital costs (TCI) 1,263

Insurance (1% total capital costs) 1% of total capital costs (TCI) 1,263

Capital Recovery 14.24% x total capital costs (TCI) 17,980 

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 88,810

Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,326

Pollutant Removed (tons/yr)B 11

Cost per ton of PM Removed 12,665

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2 Equipment cost estimates based on cost curve with 2001 vendor data.

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls MH - Low Scrub Page 2 of 16
MPCA BART Analysis 2003

Table M-2: Low Efficiency Wet Scrubber - Material Handling - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow dscfm 7,000 7143 scfm

77 Temp Deg F

2% % Moisture

 acfm 7,143

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 26.4 kW-hr 190,157 8,747 $/kW-hr, 26 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 12.9 gpm 5,554 1,222 $/Mgal, 12.9 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.0 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.0 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 12.9 gpm 5,554 8,331 $/Mgal, 12.9 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 7,000 dscfm NA 11.7 Use uncontrolled emission rate from enclosure case.

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

92% 0.9 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 10.8

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 6,429 12 0.55 0.7 23.4 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm D P ft H2O Pump Eff Motor Eff

Circ Pump 64 125 0.8 0.7 2.7 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 12.9 62.5 0.8 0.7 0.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 2.925 lb/hr SO2 2.50 lb NaOH/lb SO2 7.3 lb/hr Caustic

Lime Use 2.925 lb/hr SO2 1.53 lb Lime/lb SO2 4.5 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls MH - Low Scrub Page 3 of 16
MPCA BART Analysis 2003

Table M-3: High Efficiency Wet Scrubber - Material Handling - PM

BART Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Purchased Equipment Costs - Absorber + packing + auxillary equipment, EC 47,861

Instrumentation 10% of control device cost (A) 4,786

MN Sales Taxes 6.5% of control device cost (A) 3,111

Freight 5% of control device cost (A) 2,393

Purchased Equipment Total (B) 22% 58,151

Installation

Foundations & supports 12% of purchased equip cost (B) 6,978

Handling & erection 40% of purchased equip cost (B) 23,260

Electrical 1% of purchased equip cost (B) 582

Piping 30% of purchased equip cost (B) 17,445

Insulation 1% of purchased equip cost (B) 582

Painting 1% of purchased equip cost (B) 582

Installation Total 85% 49,428

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost, DC 107,580

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 5,815

Construction & field expenses 10% of purchased equip cost (B) 5,815

Construction fee 10% of purchased equip cost (B) 5,815

Start-up 1% of purchased equip cost (B) 582

Performance test 1% of purchased equip cost (B) 582

Contingencies 3% of purchased equip cost (B) 1,745

Total Indirect Capital Costs, IC 35% 20,353

Total Capital Investment (TCI) = DC + IC 127,932

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 11,250

Supervisor 15% of oper labor costs 15% 1,688

Operating Materials

Reagent #1 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Reagent #2 NA $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime - 

Catalyst NA - 

Wastewater Treatment 1.50 $/Mgal, 12.9 gpm, 8000 hr/yr, 90.0% of capacity 8,331

Maintenance

Maintenance Labor 17.50 1/2 hr per shift 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Electricity - Fan, Pump 0.05 $/kW-hr, 26 kW-hr, 8000 hr/yr, 90.0% of capacity 8,747

Total Annual Direct Operating Costs 47,516

Indirect Operating Costs

Overhead 60% of total labor and material costs 18,263

Administration (2% total capital costs) 2% of total capital costs (TCI) 2,559

Property tax (1% total capital costs) 1% of total capital costs (TCI) 1,279

Insurance (1% total capital costs) 1% of total capital costs (TCI) 1,279

Capital Recovery 14.24% x total capital costs (TCI) 18,215

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 89,111

Total Annual Cost (Annualized Capital Cost + Operating Cost) 136,627

Pollutant Removed (tons/yr)B 12

Cost per ton of PM Removed 11,795

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2 Equipment cost estimates based on cost curve with 2001 vendor data.

3

4

5

6

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls MH - High Scrub Page 4 of 16
MPCA BART Analysis 2003

Table M-3: High Efficiency Wet Scrubber - Material Handling - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 10 years

CRF 0.1424

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

Amount Required 0 ft

3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow dscfm 7,000 7143 scfm

77 Temp Deg F

2% % Moisture

 acfm 7,143

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 450 11,250 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor 15% of Op. NA 1,688 15% of Operator Costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 450 4,125 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 26.4 kW-hr 190,157 8,747 $/kW-hr, 26 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 12.9 gpm 5,554 1,222 $/Mgal, 12.9 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 (Lime) 300 Ton 0.0 lb/hr 0 0 $/Ton, 0.0 lb/hr, 8000 hr/yr, 62 lb/lbmole, Lime

SW Disposal 25 Ton 0.0 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.0 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 12.9 gpm 5,554 8,331 $/Mgal, 12.9 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 0 ft

3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 0 bag 0 bags 2 yr life 0 $/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 7,000 dscfm NA 11.7 Use uncontrolled emission rate from enclosure case.

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 0.1 Basis:8000 hr/yr, 90.0% of capacity

Emission Reduction T/yr 11.6

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 6,429 12 0.55 0.7 23.4 OAQPS Cost Cont Manual 6th ed - Eq 1.48

Flow gpm D P ft H2O Pump Eff Motor Eff

Circ Pump 64 125 0.8 0.7 2.7 OAQPS Cost Cont Manual 6th ed - Eq 1.49

H2O WW Disch 12.9 62.5 0.8 0.7 0.3 OAQPS Cost Cont Manual 6th ed - Eq 1.49

Caustic Use 2.925 lb/hr SO2 2.50 lb NaOH/lb SO2 7.3 lb/hr Caustic

Lime Use 2.925 lb/hr SO2 1.53 lb Lime/lb SO2 4.5 lb/hr Lime

Water Makeup Rate/WW Disch = 20% of circulating water rate

Utility use rates basis: 8000 hr/yr, 90.0% of capacity

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls MH - High Scrub Page 5 of 16
MPCA BART Analysis 2003

Table M-4: ESP - Material Handling - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 606,954

Instrumentation 10% of control device cost (A) 60,695

MN Sales Taxes 7% of control device cost (A) 39,452

Freight 5% of control device cost (A) 30,348

Purchased Equipment Total (B) 22% 737,449

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 29,498

Handling & erection 50% of purchased equip cost (B) 368,725

Electrical 8% of purchased equip cost (B) 58,996

Piping 1% of purchased equip cost (B) 7,374

Insulation for ductwork 2% of purchased equip cost (B) 14,749

Painting 2% of purchased equip cost (B) 14,749

Direct Installation Costs 494,091

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 1,231,540

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 147,490

Construction & field expenses 20% of purchased equip cost (B) 147,490

Constractor fees 10% of purchased equip cost (B) 73,745

Start-up 1% of purchased equip cost (B) 7,374

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 14,749

Contingencies 3% of purchased equip cost (B) 22,123

Total Indirect Capital Costs 57% 412,972

Total Capital Investment (TCI) = DC + IC 1,644,512

OPERATING COSTS

Direct Operating Costs

Operator 25.00 $/hr, 1 hr/shift, 8 hr/shift, 8640 hr/yr 25,000

Supervisor 15% of operator costs 3,750

Coordinator 33% of operator costs 8,250

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 5,775

Maintenance Materials 1% of purchased equipment costs 7,374

Utilities

Electricity 0.05 $/kW-hr, 15 kW-hr, 8000 hr/yr, 90.0% of capacity 5,388

Water NA - 

Solid Waste Disposal 25.00 $/Ton, 0.300 gr/dscf, 8000 hr/yr 290

Wastewater Treatment NA - 

Total Annual Direct Operating Costs, DC 55,827

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 25,140

Administration (2% total capital costs) 2% of total capital costs (TCI) 32,890

Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,445

Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,445

Captial Recovery 9% 155,230

Total Indirect Operating Costs 246,150

Total Annual Cost (Annualized Capital Cost + Operating Cost) 301,977

Pollutant Removed (tons/yr)B 11.6

Cost per ton of PM Removed 26,071

Notes & Assumptions

1 1 EPA Air Pollution Control Cost Manual 6th Ed 2002

2

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls MH - ESP Page 6 of 16
MPCA BART Analysis 2003

Table M-4: ESP - Material Handling - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft

3

Amount Required 0 ft

3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 7,000 dscfm 7143 scfm

77 Temp Deg F

2% % Moisture

7,143 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 1 hr/8 hr shift 1,000 25,000 $/hr, 1 hr/shift, 8 hr/shift, 8640 hr/yr

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft

2

 collecto 2,171 ft

2

 collector area 5,775 $/ft

2 collector area; $5775 if < 50,000 ft2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 14.6 kW-hr 117,121 5,388 $/kW-hr, 15 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft

3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.001 ton/hr 12 290 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 0.0 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft

3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 7,000 dscfm NA 11.7 Use uncontrolled emission rate from enclosure case.

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 0 Currently assumes 99%.

Emission Reduction T/yr 11.6

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower Eff kW

Blower 7,143 5 0.65 6.4 OAQPS Cost Cont Manual 6th ed - Eq 3.46

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 NA 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 NA 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 2,171 4.2 2 4 8.2 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 7,143 acfm

Area #2 2171 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls MH - ESP Page 7 of 16
MPCA BART Analysis 2003

Table M-5: Wet Wall ESP - Material Handling - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

ESP + auxillary equipment 625,163

Instrumentation 10% of control device cost (A) 62,516

MN Sales Taxes 6.5% of control device cost (A) 40,636

Freight 5% of control device cost (A) 31,258

Purchased Equipment Total (B) 22% 759,573

Direct Installation Costs

Foundations & supports 4% of purchased equip cost (B) 30,383

Handling & erection 50% of purchased equip cost (B) 379,787

Electrical 8% of purchased equip cost (B) 60,766

Piping 1% of purchased equip cost (B) 7,596

Insulation for ductwork 2% of purchased equip cost (B) 15,191

Painting 2% of purchased equip cost (B) 15,191

Direct Installation Costs 508,914

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Costs, DC 67% 1,268,487

Indirect Capital Costs

Engineering 20% of purchased equip cost (B) 151,915

Construction & field expenses 20% of purchased equip cost (B) 151,915

Constractor fees 10% of purchased equip cost (B) 75,957

Start-up 1% of purchased equip cost (B) 7,596

Performance Test 1% of purchased equip cost (B)

Model Study 2% of purchased equip cost (B) 15,191

Contingencies 3% of purchased equip cost (B) 22,787

Total Indirect Capital Costs 57% 425,361

Total Capital Investment (TCI) = DC + IC 1,693,848

OPERATING COSTS

Direct Operating Costs

Operator 12.00 $/hr, 1 hr/shift, 8 hr/shift, 8640 hr/yr 12,000

Supervisor 15% of operator costs 1,800

Coordinator 33% of operator costs 3,960

Operating materials

Maintenance Labor 0.1155 $/ft2 collector area; $5775 if < 50,000 ft2 5,775

Maintenance Materials 1% of purchased equipment costs 7,596

Utilities

Electricity 0.05 $/kW-hr, 18 kW-hr, 8000 hr/yr, 90.0% of capacity 6,499

Water 0.22 $/Mgal, 64.3 gpm, 8000 hr/yr, 90.0% of capacity 6,789

Solid Waste Disposal NA - 

Wastewater Treatment 1.50 $/Mgal, 64.3 gpm, 8000 hr/yr, 90.0% of capacity 46,286

Reagent (Caustic) 280.00 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH - 

Total Annual Direct Operating Costs, DC 90,704

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 16,302

Administration (2% total capital costs) 2% of total capital costs (TCI) 33,877

Property tax (1% total capital costs) 1% of total capital costs (TCI) 16,938

Insurance (1% total capital costs) 1% of total capital costs (TCI) 16,938

Captial Recovery 9% 159,887

Total Indirect Operating Costs 243,944

Total Annual Cost (Annualized Capital Cost + Operating Cost) 334,648

Pollutant Removed (tons/yr)B 11.6

Cost per ton of PM Removed 28,891

Notes & Assumptions

1 1 Equipment cost estimates assumed to be 3% higher than that of dry ESP.

2 EPA Cost Manual 6th Ed. 2002

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls MH - Wet ESP Page 8 of 16
MPCA BART Analysis 2003

Table M-5: Wet Wall ESP - Material Handling - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts & Catalyst 0

Design Flow 7,000 dscfm 7143 scfm

77 Temp Deg F

2% % Moisture

7,143 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 12 Hr 1 hr/8 hr shift 1,000 12,000 $/hr, 1 hr/shift, 8 hr/shift, 8640 hr/yr

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 0.1155 $/ft2

 collecto 2,171 ft2 collector area 5,775 $/ft2 collector area; $5775 if < 50,000 ft 2

Maint Mtls NA NA 1% of purchased equipment costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 17.7 kW-hr 141,282 6,499 $/kW-hr, 18 kW-hr, 8000 hr/yr, 90.0% of capacity

Natural Gas 4.24 Mft3 0 scfm 0 0 $/Mft3, 0.0 scfm, 8000 hr/yr, 90.0% of capacity

Water 0.22 Mgal 64 gpm 30,857 6,789 $/Mgal, 64.3 gpm, 8000 hr/yr, 90.0% of capacity

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/Mscf, 0.0 Mscfm, 8000 hr/yr, 90.0% of capacity

Reagent #1(Caustic) 280 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/Ton, 0.0 lb-mole/hr, 8000 hr/yr, 62 lb/lbmole, 50 wt% NaOH

SW Disposal 25 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 64 gpm 30,857 46,286 $/Mgal, 64.3 gpm, 8000 hr/yr, 90.0% of capacity

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 0.0 ft3, 2 yr life, 8000 hr/yr, 90.0% of capacity

Rep Parts 33.72 $/bag 0 bags 2 yr life 0 $/$/bag, 0.0 bags, 2 yr life, 8000 hr/yr, 90.0% of capacity

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 7,000 dscfm NA 11.7 Use uncontrolled emission rate from enclosure case.

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 0 Currently assumes 99%.

Emission Reduction T/yr 11.6

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower Eff Motor Eff kW

Blower 7,143 5 0.55 0.9 8.4 OAQPS Cost Cont Manual 5th ed - Eq 3.37

Flow gpm D P ft H2O Pump Eff Motor Eff

Pump 1 64 60 0.8 0.9 1.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Pump 2 0 60 0.8 0.9 0.0 OAQPS Cost Cont Manual 5th ed - Eq 9.49

Area sqft TR pwr # Hoppers Htr Pwr

ESP 2,171 4.2 2 4 8.2 OAQPS Cost Cont 5th ed - Eq 6.29 & 6.30

Caustic Use 2.925 lb/hr SO2 2.50 lb NaOH/lb SO2 0.004 T/hr Caustic

Lime Use 2.925 lb/hr SO2 1.53 lb Lime/lb SO2 0.002 T/hr Lime

Estimate Area (ft2)

Area #1 48503 ft2

Flow #1 159588 acfm

Flow #2 7,143 acfm

Area #2 2171 ft2

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls MH - Wet ESP Page 9 of 16
MPCA BART Analysis 2003

Table M-6: Baghouse - Material Handling - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Fabric Filter (EC) + bags + auxillary equipment 31,428

Instrumentation 10% of control device cost (A) 3,143

MN Sales Taxes 6.5% of control device cost (A) 2,043

Freight 5% of control device cost (A) 1,571

Purchased Equipment Total (B) 18% 38,185

Direct installation costs

Foundations & supports 4% of purchased equip cost (B) 1,527

Handling & erection 50% of purchased equip cost (B) 19,093

Electrical 8% of purchased equip cost (B) 3,055

Piping 1% of purchased equip cost (B) 382

Insulation for ductwork 7% of purchased equip cost (B) 2,673

Painting 4% of purchased equip cost (B) 1,527

Installation Total 74% 28,257

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost 66,442

Indirect Capital Costs

Engineering 10% of purchased equip cost (B) 3,819

Construction and field expense 20% of purchased equip cost (B) 7,637

Contractor fees 10% of purchased equip cost (B) 3,819

Startup 1% of purchased equip cost (B) 382

Performance test 1% of purchased equip cost (B) 382

Contingencies 3% of purchased equip cost (B) 1,146

Total Indirect Capital Costs 45% 17,183

Total Capital Investment (TCI) = DC + IC 83,625

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 50,000

Supervisor 15% of operator labor costs 7,500

Maintenance Labor 17.50 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 17,500

Maintenance Materials 100% of maintenance labor costs 17,500

Replacement parts, bags 4,793

Utilities

 Electricity 0.05 $/kW-hr, 36.4 kW; 8640 hr/yr 22,837

 Compressed Air 0.27 $/mscf, 100 scfm, 8640 hr/yr 1,851

 Solid Waste Disposal 25.00 $/Ton, 0.300 gr/dscf, 8000 hr/yr 290

Total Annual Direct Operating Costs (DC) 122,271

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 55,500

Administration (2% total capital costs) 2% of total capital costs (TCI) 1,673

Property tax (1% total capital costs) 1% of total capital costs (TCI) 836

Insurance (1% total capital costs) 1% of total capital costs (TCI) 836

Capital Recovery 9% for a 20- year equipment life and a % interest rate 7,894

Total Indirect Operating Costs 66,739

Total Annual Cost (Annualized Capital Cost + Operating Cost) 189,010

Pollutant Removed (tons/yr)B 12

Cost per ton of PM Removed 16,318

Notes & Assumptions

1 EPA Cost Manual 6th Ed. 2002

2

3

4

5

6

7

8

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls MH - Baghouse Page 10 of 16
MPCA BART Analysis 2003

Table M-6: Baghouse - Material Handling - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0%

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 35 $ each

Amount Required 114 Number

Total Rep Parts Cost 4,460 Cost adjusted for freight & sales tax

Installation Labor 333 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 4,793

Annualized Cost 2,651

Total Cost Replacement Parts (Bags) 4,793

Design Flow 7,000 dscfm 7143 scfm

77 Temp Deg F

2% % Moisture

7,143 acfm

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 2 hr/8 hr shift 2,000 50,000 $/Hr, 2.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.5 Hr 1 hr/8 hr shift 1,000 17,500 $/Hr, 1.0 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 62.1 kW-hr 496,457 22,837 $/kW-hr, 36.4 kW; 8640 hr/yr

Natural Gas 4.24 Mft3 0 scfm 0 0 $/mscf, 40 scfm, 8000 hr/yr

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 7.16 gpm; 8000 hr/yr

Comp Air 0.27 Mscf Mscfm 14.29 6,857 1,851 $/mscf, 100 scfm, 8640 hr/yr

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/T, 62 lb/lbmole, 0.76wt% NaOH, 8000 hr/yr

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/T, 62 lb/lbmole, 0.76wt% NaOH, 8000 hr/yr

SW Disposal 25 Ton 0.001 ton/hr 12 290 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 7.16 gpm; 8000 hr/yr

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 39 ft3 of catalyst, 2 yr cat life

Rep Parts 35 bag 114.2857143 bags 2 yr life 2,651 795 bags, 2 yr life

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 7,000 dscfm NA 11.7 Use uncontrolled emission rate from enclosure case.

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

99% 0 Currently assumes 99%.

Emission Reduction T/yr 11.6

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 7,143 6 0.65 62.1 OAQPS Cost Cont Manual 6th ed - Eq 1.14

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MPCA BART Analysis 2003

Table M-7: Multiclone - Material Handling - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Equipment Cost 88,752

Instrumentation 10% of control device cost (A) 8,875

MN Sales Taxes 6.5% of control device cost (A) 5,769

Freight 5% of control device cost (A) 4,438

Purchased Equipment Total (B) 18% 107,834

Direct installation costs

Foundations & supports 4% of purchased equip cost (B) 4,313

Handling & erection 40% of purchased equip cost (B) 43,133

Electrical 8% of purchased equip cost (B) 8,627

Piping 1% of purchased equip cost (B) 1,078

Insulation for ductwork 7% of purchased equip cost (B) 7,548

Painting 4% of purchased equip cost (B) 4,313

Installation Total 74% 69,014

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost 176,847

Indirect Capital Costs

Engineering 10% of purchased equip cost (B) 10,783

Construction and field expense 10% of purchased equip cost (B) 10,783

Contractor fees 10% of purchased equip cost (B) 10,783

Startup 1% of purchased equip cost (B) 1,078

Performance test 1% of purchased equip cost (B) 1,078

Contingencies 3% of purchased equip cost (B) 3,235

Total Indirect Capital Costs 45% 37,742

Total Capital Investment (TCI) = DC + IC 214,589

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 12,500

Supervisor 15% of operator labor costs 1,875

Maintenance Labor 17.50 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity 8,750

Maintenance Materials 100% of maintenance labor costs 8,750

Replacement parts, bags 0

Utilities

 Electricity 0.05 $/kW-hr, 36.4 kW; 8640 hr/yr 228,370

 Compressed Air NA - 

 Solid Waste Disposal 25.00 $/Ton, 0.300 gr/dscf, 8000 hr/yr 2,340

Total Annual Direct Operating Costs (DC) 262,585

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 19,125

Administration (2% total capital costs) 2% of total capital costs (TCI) 4,292

Property tax (1% total capital costs) 1% of total capital costs (TCI) 2,146

Insurance (1% total capital costs) 1% of total capital costs (TCI) 2,146

Capital Recovery 9% for a 20- year equipment life and a 7% interest rate 20,256

Total Indirect Operating Costs 47,964

Total Annual Cost (Annualized Capital Cost + Operating Cost) 310,550

Pollutant Removed (tons/yr)B 94

Cost per ton of PM Removed 3,318

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002. Assumed same cost factors as baghouse. 

2 Reduced erection to 40% and Const Field Exp to 10% to address simpler installation.

3 Reduced operator and maintenance hours to address simpler operation.

Design flow rate was increased by a factor of 10 to provide values large enough to create a cost estimate for multiclone. Original 

4 parameters were too small for vendor to provide estiamte for a multiclone.

5

6

7

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MPCA BART Analysis 2003

Table M-7: Multiclone - Material Handling - PM (Continued)

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0% 7

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts (Bags) 0

Design Flow 7,000 dscfm 7143 scfm

77 Temp Deg F

2% % Moisture Scaled x10 to provide flow large enough for cost estimate

7,143 acfm acfm 71,429

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.5 hr/8 hr shift 500 12,500 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.5 Hr 0.5 hr/8 hr shift 500 8,750 $/Hr, 0.5 hr/8 hr shift, 8000 hr/yr, 90.0% of capacity

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 620.6 kW-hr 4,964,571 228,370 $/kW-hr, 36.4 kW; 8640 hr/yr

Natural Gas 4.24 Mft3 0 scfm 0 0 $/mscf, 40 scfm, 8000 hr/yr

Water 0.22 Mgal 0 gpm 0 0 $/Mgal, 7.16 gpm; 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/mscf, 100 scfm, 8640 hr/yr

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/T, 62 lb/lbmole, 0.76wt% NaOH, 8000 hr/yr

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/T, 62 lb/lbmole, 0.76wt% NaOH, 8000 hr/yr

SW Disposal 25 Ton 0.012 ton/hr 94 2,340 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.300 gr/dscf, 8000 hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 7.16 gpm; 8000 hr/yr

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 39 ft3 of catalyst, 2 yr cat life

Rep Parts 33.72 bag 0 bags 2 yr life 0 795 bags, 2 yr life

*annual use rate is in same units of measurement as the unit cost factor

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Flow Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

0.3 gr/dscf 70,000 dscfm NA 117.0 Use uncontrolled emission rate from enclosure case.

Controlled Emission Rate 

Perf Unit of Flow Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

80% 23 Currently assumes 80%.

Emission Reduction T/yr 93.6

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 71,429 6 0.65 620.6 OAQPS Cost Cont Manual 6th ed - Eq 1.14

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MPCA BART Analysis 2003

Table M-8: Enclosure - Material Handling - PM

BACT Emission Control Cost Analysis

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (1)

Fabric Filter (EC) + bags + auxillary equipment 23,000

Instrumentation 10% of control device cost (A) 2,300

MN Sales Taxes 6.5% of control device cost (A) 1,495

Freight 5% of control device cost (A) 1,150

Purchased Equipment Total (B) 18% 27,945

Direct installation costs

Foundations & supports 4% of purchased equip cost (B) 1,118

Handling & erection 40% of purchased equip cost (B) 11,178

Electrical 8% of purchased equip cost (B) 2,236

Piping 1% of purchased equip cost (B) 279

Insulation for ductwork 7% of purchased equip cost (B) 1,956

Painting 4% of purchased equip cost (B) 1,118

Installation Total 74% 17,885

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Total Direct Capital Cost 45,830

Indirect Capital Costs

Engineering 10% of purchased equip cost (B) 2,795

Construction and field expense 10% of purchased equip cost (B) 2,795

Contractor fees 10% of purchased equip cost (B) 2,795

Startup 1% of purchased equip cost (B) 279

Performance test 1% of purchased equip cost (B) 279

Contingencies 3% of purchased equip cost (B) 838

Total Indirect Capital Costs 45% 9,781

Total Capital Investment (TCI) = DC + IC 55,611

OPERATING COSTS

Direct Operating Costs

Operating Labor 25.00 $/Hr, 0.1 hr/8 hr shift, hr/yr, 0.0% of capacity 2,500

Supervisor 15% of operator labor costs 375

Maintenance Labor 17.50 $/Hr, 0.1 hr/8 hr shift, hr/yr, 0.0% of capacity 1,750

Maintenance Materials 100% of maintenance labor costs 1,750

Replacement parts, bags 0

Utilities

 Electricity 0.05 $/kW-hr, 36.4 kW; 8640 hr/yr 34,303

 Compressed Air NA - 

 Solid Waste Disposal NA - 

Total Annual Direct Operating Costs (DC) 40,678

Indirect Operating Costs

Overhead 60% of oper, maint & supv labor + maint mtl costs 3,825

Administration (2% total capital costs) 2% of total capital costs (TCI) 1,112

Property tax (1% total capital costs) 1% of total capital costs (TCI) 556

Insurance (1% total capital costs) 1% of total capital costs (TCI) 556

Capital Recovery 9% for a 20- year equipment life and a 7% interest rate 5,249

Total Indirect Operating Costs 11,299

Total Annual Cost (Annualized Capital Cost + Operating Cost) 51,977

Pollutant Removed (tons/yr)B 11

Cost per ton of PM Removed 4,586

Notes & Assumptions

1 EPA Air Pollution Control Cost Manual 6th Ed 2002. Assumed same cost factors as baghouse.

2 Reduced erection to 40% and Const Field Exp to 10% to address simpler installation.

3 Reduced operator and maintenance hours to address simpler operation.

4

5

6

7

8

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MPCA BART Analysis 2003

Capital Recovery Factors Enter Data in Blue Highlighted Cells

Primary Installation Data to Summary Table in Yellow Highlighted Cells

Interest Rate 7.0% 7

Equipment Life 20 years

CRF 0.0944

Catalyst Replacement Cost

Catalyst Life 2 years

CRF 0.5531

Catalyst cost per unit 650 $/ft3

Amount Required 0 ft3

Catalyst Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0

Annualized Cost 0

Replacement Parts & Equipment

Equipment Life 2 years

CRF 0.5531

Rep part cost per unit 33.72 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 10 min per bag (13 hr total) Labor at $29.65/hr

Total Installed Cost 0

Annualized Cost 0

Total Cost Replacement Parts (Bags) 0

Design Flow dscf 7,000 m 7143 scfm

77 Temp Deg F

2% % Moisture

 acf 7,143 m

Operating Cost Calculations Annual hours of operation: 8,000

Utilization Rate: 90.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Op Labor 25 Hr 0.1 hr/8 hr shift 100 2,500 $/Hr, 0.1 hr/8 hr shift, hr/yr, 0.0% of capacity

Supervisor NA NA NA Calc'd as % of labor costs

Maint Labor 17.5 Hr 0.1 hr/8 hr shift 100 1,750 $/Hr, 0.1 hr/8 hr shift, hr/yr, 0.0% of capacity

Maint Mtls NA NA NA Calc'd as % of labor costs

Utilities, Reagents, Waste Management & Replacements

Electricity 0.046 kW-hr 93.2 kW-hr 745,720 34,303 $/kW-hr, 36.4 kW; 8640 hr/yr

Natural Gas 4.24 Mft3 0 scfm 0 0 $/mscf, 40 scfm, 8000 hr/yr

Water 0.2 Mgal 0 gpm 0 0 $/Mgal, 7.16 gpm; 8000 hr/yr

Comp Air 0.27 Mscf 0 Mscfm 0 0 $/mscf, 100 scfm, 8640 hr/yr

Reagent #1(Caustic) 300 Ton 0 lb-mole/hr 0 0 $/T, 62 lb/lbmole, 0.76wt% NaOH, 8000 hr/yr

Reagent #2 300 Ton 0 lb-mole/hr 0 0 $/T, 62 lb/lbmole, 0.76wt% NaOH, 8000 hr/yr

SW Disposal 0 Ton 0.857 ton/hr 6,857 0 $/Ton, 0.005 lb PM/ton taconite, hr/yr 

Haz W Disp 273 Ton 0.000 ton/hr 0 0 $/Ton, 0.005 lb PM/ton taconite, hr/yr 

WW Treat 1.5 Mgal 0 gpm 0 0 $/Mgal, 7.16 gpm; 8000 hr/yr

Catalyst 650 ft3 0 ft3 2 yr life 0 $/ft3, 39 ft3 of catalyst, 2 yr cat life

Rep Parts 33.72 bag 0 bags 2 yr life 0 795 bags, 2 yr life

*annual use rate is in same units of measurement as the unit cost facto

Emission Control Rate Calculation

Uncontrolled Emission Rate 

Emission Unit of Load Unit of Control Eff. Emis Rate

Factor Measure Rate Measure % T/yr Comments/Notes

4.67E-03 lb PM/ton taconite ton/y 5,000,000 r NA 11.7 Uncontrolled EF is based on a maximum wind speed of 15 mph per EPA AP-42 13.2.4

Controlled Emission Rate 

Perf Unit of Load Unit of Control Eff. Emis Rate

Guarantee Measure Rate Measure % T/yr Comments/Notes

1.38E-04 lb PM/ton taconite 5,000,000 ton/yr NA 0.3 Controlled EF is based on a maximum wind speed of 1 mph per EPA AP-42 13.2.4.

Emission Reduction T/yr 11.3

Estimated % Control = 97%

Electrical Consumption Requirements Kilowatts

Flow acfm D P in H2O Blower-Motor Eff kW

Blower 0 6 0.65 0.0 OAQPS Cost Cont Manual 6th ed - Eq 1.14

Table M-8: Enclosure - Material Handling - PM (Continued)

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MPCA BART Analysis 2003

Calculate Emission Factors using EPA AP-42 13.2.4: Aggregate Handling and Storage Piles

EQ: E = k*0.0032*[(U/5)^1.3/(M/2)^1.4] [=] lb PM/ton ore.

Controlled Conditions - EF

Given:

k = 0.35 Particle Size Multiplier for < 10 mm (unitless)

U = 1 mph, mean wind speed, (AP-42 range 1.3-15 mph)

M = 2.0 %, material moisture content, (AP-42 range 0.05-2.0)

E = 1.38E-04 lb PM/ton taconite

Uncontrolled Conditions - EF

Given:

k = 0.35 Particle Size Multiplier for < 10 mm (unitless)

U = 15 mph, mean wind speed, (AP-42 range 1.3-15 mph)

M = 2.0 %, material moisture content, (AP-42 range 0.05-2.0)

E = 4.67E-03 lb PM/ton taconite

Table M-8: Enclosure - Material Handling - PM (Continued)

P:\23\62\833 - MPCA Tac BART\Merged Report\Attachment M.xls MH - Enclosure Page 16 of 16
ATTACHMENT N 

Control Technology Literature Search References 
Literature 

Source/Author Source Type Pollutant Technology

Control 

Efficiency Operating Limits Consumables Waste

Other Special 

Requirements

(e.g. Blowers/Gas 

Conditioning for 

ESP's) 

EPA-600/R-00-093 Boiler SOx Wet FGD - limestone 52-98%

scaling problems w/o blowing air into absorbent slurry Limestone

By-Product 

Gypsum

blowers (limit scaling problems)

Adding SO2 reSee C

EPA-600/R-00-093 Boiler SOx Wet FGD - Ammonia ≥ 95% Ammonia

Ammonia 

Sulfate, Aerosol 

emissions

Offers by-proAeroso

EPA-600/R-00-093 Boiler SOx Dry FGD ≥ 90% high sulfur coal affects CE.

Best fosulfur 

Clean Coal Program - DOE Kiln Flue Gas SOx

Cement Kiln Flue Gas Recovery Scrubber 89.20%

Caustic. Limestone Wastewater

Produproduc

Clean Coal Program - DOE NOx

Cement Kiln Flue Gas Recovery Scrubber 18.80%

Caustic. Limestone Wastewater

Produproduc

EPA Docket A-96-56, II-A-03

Boiler - Coal, Oil or Gas Fired NOx Combustion Control 40-70% 0.15 lb/MMBTU NOx limit

Combburner

EPA Docket A-96-56, II-A-03

Boiler - Coal, Oil or Gas Fired NOx SCR 80-90% 0.15 lb/MMBTU NOx limit Spent Catalyst

Technboilers

EPA Docket A-96-56, II-A-03

Boiler - Coal, Oil or Gas Fired NOx SNCR 30-50% 0.15 lb/MMBTU NOx limit

RBLC - Kiln Rotary Kiln PM Fabric Filter 99% Solid WasteRBLC - Kiln Rotary Kiln NOx

Low NOx Burners, SNCR 8 lbs/ton klinker Natural Gas

RBLC - Kiln Rotary Kiln SOx Wet Scrubber 12 lbs/ton klinker WastewaterRBLC - Kiln

Incinerator, Rotary Kiln, Hazardous Waste NOx

Abatement rxn. Chamber with urea 20% Urea

RBLC - Kiln

Incinerator, Rotary Kiln, Hazardous Waste PM Venturi Scrubber 99.86%

Limestone, Caustic Wastewater

RBLC - Kiln Rotary Kiln - Cement PM ESP Solid WasteRBLC - Kiln Rotary Kiln - Cement SOx Fuel limits NoneRBLC - Kiln

Fugitive - Material Handling and Storage PM EPA Method 5, 9 None

RBLC - Kiln Material Handling, Lime PM

Wet Suppression, covers & partial enclosure 95.00% 5.6 TPY

AWMA Glass Plant Furnace PM Furnace DesignAWMA Glass Plant Furnace PM ESP Solid WasteAWMA Glass Plant Furnace PM Baghouse Filters Solid WasteAWMA NOx Paper #1 NOx SCR 90-97% Catalyst Spent Catalyst See T

Page 1 of 4
Literature 

Source/Author Source Type Pollutant Technology

Control 

Efficiency Operating Limits Consumables Waste

Other Special 

Requirements

(e.g. Blowers/Gas 

Conditioning for 

ESP's) 

AWMA NOx Paper #1 NOx ULNB 80.00% Natural Gas None See TAWMA NOx Paper #1 NOx

Different levels of burners Natural Gas None See T

AWMA NOx Paper #1 NOx

Flue Gas Recirculation 55% See T

AWMA NOx Paper #1 NOx SNCR 50-70% See TAWMA NOx Paper #1 NOx Catalytic Scrubbing 70% Catalyst Spent Catalyst See TNOx Controls for Existing Utility Boilers Wall Fired Boiler NOx OFA 70 - 80 %NOx Controls for Existing Utility Boilers Wall Fired Boiler NOx LNB 45 - 60% Natural Gas NoneNOx Controls for Existing Utility Boilers Wall Fired Boiler NOx LNB+OFA 35 - 55% Natural Gas NoneNOx Controls for Existing Utility Boilers Tangential Fired Boiler NOx LNB+SOFA 30 - 45 % Natural Gas NoneNOx Controls for Existing Utility Boilers Wall Fired Boiler NOx SNCR 50 - 65 % NoneNOx Controls for Existing Utility Boilers Wall Fired Boiler NOx SCR 15 - 25% Catalyst Spent CatalystNOx Controls for Existing Utility Boilers Tangential Fired Boiler NOx SNCR 0.30 - 0.40 NoneNOx Controls for Existing Utility Boilers Tangential Fired Boiler NOx SCR 0.10 - 0.15 Catalyst Spent CatalystNOx Controls for Existing Utility Boilers Boiler NOx NGR 0.50 - 0.70 None NoneNOx Controls for Existing Utility Boilers

Wall Fired Boiler - fuel: Oil, Gas NOx BOOS 0.30 - 0.35 None None

NOx Controls for Existing Utility Boilers

Wall Fired Boiler - fuel: Oil, Gas NOx FGR 0.25 - 0.35 None None

NOx Controls for Existing Utility Boilers

Wall Fired Boiler - fuel: Oil, Gas NOx LNB 0.25 - 0.30 Natural Gas None

Page 2 of 4
Literature 

Source/Author Source Type Pollutant Technology

Control 

Efficiency Operating Limits Consumables Waste

Other Special 

Requirements

(e.g. Blowers/Gas 

Conditioning for 

ESP's) 

NOx Controls for Existing Utility Boilers

Wall Fired Boiler - fuel: Oil, Gas NOx LNB+OFA+FGR 0.10 - 0.20 Natural Gas None

NOx Controls for Existing Utility Boilers

Tangential Fired Boiler - fuel: Oil, Gas NOx BOOS 0.20 - 0.25 None None

NOx Controls for Existing Utility Boilers

Tangential Fired Boiler - fuel: Oil, Gas NOx LNB 0.15 - 0.25 Natural Gas None

NOx Controls for Existing Utility Boilers

Wall Fired Boiler - fuel: Oil, Gas NOx SNCR 0.25 - 0.30 None None

NOx Controls for Existing Utility Boilers

Wall Fired Boiler - fuel: Oil, Gas NOx SCR 0.10 - 0.15 Catalyst Spent Catalyst

NOx Controls for Existing Utility Boilers

Tangential Fired Boiler - fuel: Oil, Gas NOx SNCR 0.15 - 0.20 None None

NOx Controls for Existing Utility Boilers

Tangential Fired Boiler - fuel: Oil, Gas NOx SCR 0.05 - 0.10 Catalyst Spent Catalyst

RBLC- National Steel SOx

H2S CONCENTRATION OF COKE OVEN GAS (FUEL) LIMITED TO 2.64 GR/DSCF2033 TPY None None

RBLC- National Steel NOx

Emission 

Limit:

Total limit of 

both gases:

Rich Gas - 493.8 TPYLean Gas - 581.9959.5 tpy None None

RICH' GAS)TLB/NOLIMIT FURNOVEN 

RBLC - ISPAT NOx Low NOx Burners

FUEL USE IS LIMITED TO 270 MMBTU/HR FOR ALL EU26 BURNERS COMBINED (4 STACKS) IN ADDITION TO THE USE OF EXISTING LOW NOX BURNERS. 11 CONTROL OPTIONS EXAMINED. Natural Gas None

A PSD ErroneIndurawith Lowith thThoroThe Lion Co

Page 3 of 4
Literature 

Source/Author Source Type Pollutant Technology

Control 

Efficiency Operating Limits Consumables Waste

Other Special 

Requirements

(e.g. Blowers/Gas 

Conditioning for 

ESP's) 

Dry Low NOx Memo - Combined Cycle Natural Gas Turbines NG Turbines NOx SCR 80 - 90% 2.5 - 4.5 ppm Catalyst Spent Catalyst

SCR is tempetempecan capass tCatalycan cacatalysThe uscatalyscatalysslip emspent 

NotesFGD = Flue Gas DesulfurizationSCR = Selective Catalytic ReductionSNCR = Selective Non-Catalytic ReductionESP = Electrostatic PrecipitatorULNB = Ultra Low NOx BurnerLNB = Low NOx BurnerOFA = "Overfire Air", a NOx combustion modification technology.SOFA = "Separate Overfire Air", a NOx combustion modification technology.BOOS = Burners Out of ServiceFGR = Flue Gas RecirculationNGR = Natural Gas Reburning

Page 4 of 4
ATTACHMENT O 

Applicable Minnesota Air Regulations 
Minnesota Rules, Chapter 7007. Current as of 12/19/01

 7007.0800 PERMIT CONTENT. 

 Subpart 1. Scope. The agency shall include the permit 

 conditions specified in this part in all permits, except where  the requirement states that it applies only to part 70 permits  or only to state permits. The permit shall specify and  reference the origin of and the authority for each term or  condition, and shall identify any difference in form from the  requirement giving rise to the condition. Nothing in this part  shall be read to limit the agency's authority to put additional  or more stringent terms in a permit, to conduct inspections, or  to request information.  Subp. 2. Emission limitations and standards. The permit 

 shall include emissions limitations, operational requirements,  and other provisions needed to ensure compliance with all  applicable requirements at the time of permit issuance. The  permit shall also include any condition the agency determines to  be necessary to protect human health and the environment. The  permit shall state that, where another applicable requirement of  the act is more stringent than any applicable requirement of  regulations promulgated under title IV of the act (Acid  Deposition Control), both provisions shall be incorporated into  the permit and shall be enforceable by the administrator.  Subp. 3. Emissions units covered by permit. The permit  shall cover any emissions unit within the stationary source for  which there is an applicable requirement, and any unit which the  agency believes should be covered in order to protect human  health and the environment. However, if a stationary source is  not a major source and the sole reason it is required to have a  permit is because it is subject to federal standards described  under part 7007.0250, subpart 2, then the permit shall only 

 cover emissions units regulated by those federal standards. The  permit shall include applicable requirements for fugitive  emissions in the same manner as stack emissions, regardless of  whether the source category in question is included in the list  of sources contained in the definition of major source in part 

7007.0200, subpart 2. 

 Subp. 4. Monitoring. The agency shall include the  following monitoring requirements in all permits:  A. The permit shall require the permittee to comply  with all emissions monitoring and analysis procedures or test  methods required under the applicable requirements, including  any procedures and methods promulgated pursuant to section  114(a)(3) or 504(b) of the act.  B. For part 70 permits, where the applicable  requirements do not require periodic testing or instrumental or  noninstrumental monitoring (which may consist of recordkeeping  designed to serve as monitoring), the permit shall require the  permittee to conduct periodic monitoring sufficient to determine  whether the stationary source is in compliance with applicable  requirements. The monitoring requirements shall be designed to 

 yield reliable data from the relevant  representative of the stationary sourc require the permittee to use terms, te averaging periods, and other statistic consistent with the emissions limitati contained in the permit, and with othe requirements. Recordkeeping provision meet the requirements of this item.  C. For state permits, where peri instrumental or noninstrumental monito recordkeeping designed to serve as mon by item A, the permit shall include mo sufficient to determine whether a stat compliance with applicable requirement that such monitoring is warranted by:  (1) the likelihood of noncompli (2) the environmental impact of  (3) the likelihood that noncomp be detected using means other than mon D. As necessary, the permit shal permittee to install, use, and maintai use monitoring methods.  Subp. 5. Recordkeeping. The permi applicable requirements related to rec permittee to maintain adequate records following:  A. A requirement that the permit adequate to document compliance at the  including at a minimum:  (1) the date, place, as defined  and time of sampling or measurements;  (2) the date or dates analyses  (3) the company or entity that  analyses;  (4) the analytical techniques o (5) the results of such analyse (6) the operating conditions ex of sampling or measurement.  B. A requirement that the permit describing any modification made at th parts 7007.1250 and 7007.1350, as requ

 but not otherwise regulated under the  resulting from those changes.  C. A requirement that the permit all monitoring data and support inform years, or longer as specified by the c of the monitoring sample, measurement,  information includes all calibration a all original recordings for continuous  instrumentation, and copies of all rep permit. Records shall be kept at the  the permit allows otherwise. 
 D. A requirement that the permittee retain copies of 

 deviation reports required by subpart 6 for a period of five  years, or longer if requested by the commissioner, from the date  of submittal of the report to the agency.  Subp. 6. Reporting. The permit shall require the  permittee to submit to the agency the reports described in this  subpart. The permit shall require that all reports be certified  by a responsible official consistent with part 7007.0500, 

 subpart 3.  A. Deviation reporting time frames are described in  subitems (1) and (2).  (1) For deviations that endanger human health or  the environment, the permit shall require the permittee to  notify the commissioner as required in part 7019.1000, subpart 

1.  (2) For all other deviations, the permit shall  require the permittee to submit a deviation report, on a form  approved by the commissioner, at least semiannually. The report  is due whether or not a deviation occurred during the reporting  period. The midyear deviations report, covering deviations  which occurred during the period from January 1 to June 30, is  due by July 30 of each year and the end-of-year deviations  report, covering deviations which occurred during the period  from July 1 to December 31, is due by January 30 of each year.  B. All part 70 permits shall require the permittee to  submit progress reports at least every six months for any  stationary source required to have a compliance schedule under  part 7007.0500, subpart 2, item K, subitem (4). Such progress  reports shall contain the deadlines for achieving the  activities, milestones, or compliance required in the compliance  schedule and dates when such activities, milestones, or  compliance were actually achieved. If any deadlines in the  schedule of compliance were not or will not be met, the report  shall note that, explain why, and include any preventive or  corrective measures that have been or will be adopted as a  result.  C. The permit shall require submittal of an annual  compliance certification by January 31 of each year to the  agency. In the case of part 70 permits, compliance  certifications shall be submitted to the administrator as well  as the agency, unless the administrator agrees that the  submittals are not necessary. The certification shall be on a  form approved by the commissioner and shall contain the  following:  (1) the facility name and permit number;  (2) identification of the calendar year that the  report covers;  (3) identification of deviation reports submitted  covering the calendar year including the name of report (i.e.  DRF-1 or DRF-2), the period covered by the report, and the date  of the cover letter accompanying the report;  (4) identification of any noncompliance with 

 applicable requirements or a permit co identified in deviation reports submit the calendar year;  (5) a certification that meets  of part 7007.0500, subpart 3;  (6) the signature and title of  official as defined in part 7007.0100, 

 (7) additional requirements as  pursuant to sections 114(a)(3) and 504 Notwithstanding any other provision  requirement, for the purpose of submis certifications under this item, the ow prohibited from using the following in  methods:  (a) a monitoring protocol app source pursuant to Code of Federal Reg 64, as amended; and  (b) any other monitoring meth into a permit issued under this chapte D. All progress reports and comp described in this subpart are availabl and copying at the agency upon request provisions of part 7000.1200 and Minne and section 116.075.  E. For deviations caused by emer in part 7007.1850, the permittee may a

 defense only if it meets all the requi which includes notifying the agency wi when the emission limitations were excemergency.  Subp. 7. Prohibition on exceedance  affected sources, the agency shall inc prohibiting emissions exceeding any al stationary source lawfully holds under  the regulations promulgated thereunder A. No permit amendment shall be  increases in emissions that are author acquired pursuant to the acid rain pro increases do not require a permit amen applicable requirement.  B. No limit shall be placed on t allowances held by the stationary sour may not, however, use allowances as a  with any other applicable requirement.  C. Any such allowance shall be a according to the procedures establishe Regulations, title 40, part 73, as ame Subp. 8. Fee requirement. The per payment of annual fees by owners or op source required to pay annual fees due 

 Subp. 9. Additional compliance req shall contain the following elements w
 A. inspection and entry requirements that require 

 that, upon presentation of credentials and other documents as  may be required by law, the permittee shall allow the agency, or  an authorized representative or agent of the agency, to perform  the following:  (1) enter upon the permittee's premises where the  stationary source is located or activity is conducted, or where  records must be kept under the conditions of the permit;  (2) have access to and copy, at reasonable times,  any records that must be kept under the conditions of the  permit;  (3) inspect at reasonable times any facilities,  equipment (including monitoring and air pollution control  equipment), practices, or operations regulated or required under  the permit. For purposes of this subpart, reasonable times  include any time that the stationary source is operating; and  (4) sample or monitor any substances or  parameters at any location:  (a) at reasonable times, for the purposes of  assuring compliance with the permit or applicable requirements;  or  (b) as otherwise authorized by the act or  state law;  B. a schedule of compliance if one is required under  part 7007.0500, subpart 2, item K, meeting the description of  that part; and  C. provisions establishing the permit shield  described in part 7007.1800.  Nothing in this subpart shall be read to limit the agency's  authority under Minnesota Statutes, section 116.091, and section 

 114 of the act (Recordkeeping, Inspections, Monitoring, and  Entry) or other law.  Subp. 10. Emissions trading. A. If requested by a permit applicant, the agency  shall include provisions allowing the permittee to trade  emissions increases and decreases that occur within the  permitted facility. No title I modification may be made using  this provision, and the trade may not result in the exceedance  of any facility-wide emission limit in the permit. The agency  shall make such trading available to the permittee only if it  determines that all of the following are true:  (1) the unit-specific limits above which the  permittee wishes to increase emissions were established solely  to keep the stationary source as a whole from being subject to  an applicable requirement described in part 7007.0100, subpart 

 7, items A to K, and are independent of otherwise applicable  requirements;  (2) the stationary source's total emissions can  be limited equally well, and compliance with applicable  requirements may still be assured, by allowing the proposed  trading scenario; and  (3) the permit establishes replicable procedures 

 to ensure the emission trades are quan B. The permit shall require the  the agency in writing at least seven w the emissions trade the written notifi item. The notice shall state when the  describe the change in emissions that  shall also describe how these increase emissions will comply with the terms a permit. The permittee and the agency  notice to its copy of the stationary s Subp. 11. Alternative scenarios.  allowing for reasonably anticipated al scenarios identified by the stationary  application. Such terms and condition A. require the stationary source with making a change from one operatin record in a log at the permitted facil scenario under which it is operating;  B. ensure that the operation und alternative scenario complies with all  and the requirements of parts 7007.010

 Subp. 12. Operation in more than o requested by the applicant, the permit  source to be operated in more than one  course of the permit. No affected sou option. If more than one location is  shall include the following:  A. identification of all geograp stationary source is authorized to ope the permit;  B. conditions that will assure c applicable requirements at all authori C. requirements that the owner o agency at least ten days in advance of  providing the exact location where the  all part 70 permits and at least 48 ho change in location for all other state  D. conditions that assure compli provisions of parts 7007.0100 to 7007.

 Subp. 13. Permit duration. Each p duration of the permit, or state that  Subp. 14. Operation of control equ commissioner determines that such prov improve the likelihood of future permi may specify operating and maintenance  piece of control equipment located at  require the permittee to maintain an o plan on site.  Subp. 15. Terms to include in reis shall indicate the terms that must be  of the permit under part 7007.0450, su Subp. 16. General conditions. Per
 agency under parts 7007.0100 to 7007.1850 shall include the 

 following general conditions, either expressly or by reference  to this subpart.  A. Unchallenged provisions of this permit remain  valid despite any successful challenges to specific portions of  the permit.  B. The permittee must comply with all conditions of  the permit. Any permit noncompliance constitutes a violation of  the state law and, if the provision is federally enforceable, of  the act. Such violation is grounds for enforcement action by  the agency or the EPA; or for permit termination, revocation and  reissuance, or amendment; or for denial of a permit reissuance  application.  C. It is not a defense for a permittee in an  enforcement action that it would have been necessary to halt or  reduce the permitted activity in order to maintain compliance  with the conditions of this permit.  D. This permit may be reopened and amended or revoked  for cause as provided in parts 7007.1600 to 7007.1700. The 

 filing of a request by the permittee for a permit amendment,  revocation and reissuance, or termination, or of a notification  of planned changes or anticipated noncompliance does not stay  any permit condition, except as specifically provided in part 

7007.1450, subpart 7. 

 E. This permit does not convey any property rights of  any sort, or any exclusive privilege.  F. The permittee shall furnish to the agency, within  a reasonable time, any information that the agency may request  in writing to determine whether cause exists for reopening and  amending or revoking the permit or to determine compliance with  the permit. Upon request, the permittee shall also furnish to  the agency copies of records required to be kept by the  permittee.  G. The agency's issuance of a permit does not release  the permittee from any liability, penalty, or duty imposed by  Minnesota or federal statutes or rules or local ordinances,  except the obligation to obtain the permit or as specifically  provided in the permit shield provision and part 7007.1800.  H. The agency's issuance of a permit does not prevent  the future adoption by the agency of pollution control rules,  standards, or orders more stringent than those now in existence  and does not prevent the enforcement of these rules, standards,  or orders against the permittee.  I. The agency's issuance of a permit does not  obligate the agency to enforce local laws, rules, or plans  beyond that authorized by Minnesota statutes.  J. The permittee shall at all times properly operate  and maintain the facilities and systems of treatment and control  and the appurtenances related to them which are installed or  used by the permittee to achieve compliance with the conditions  of the permit. Proper operation and maintenance includes  effective performance, adequate funding, adequate operator 

 staffing and training, and adequate la controls, including appropriate qualit K. The permittee may not knowing misleading statement, representation,  record, report, plan, or other documen to the agency or to the commissioner b permittee shall immediately upon disco commissioner an error or omission in t plans, or other documents. The permit tamper with, render inaccurate, or fai monitoring device or method required t followed by the permit.  L. The permittee shall, when req commissioner, submit within a reasonab and reports that are relevant to pollu authorized under this permit.  M. If the permittee discovers, t including notification by the agency,  condition of the permit has occurred,  immediately take all reasonable steps  impact on human health or the environm noncompliance.  N. The permit is not transferabl except as provided in part 7007.1400, 

 O. The permit authorizes the per activities described in the permit und permit. In issuing the permit, the st responsibility for damages to persons,  environment caused by the activities o conduct of its actions, including thos directed, or undertaken under the perm state and agency may be liable for the  employees, that liability is explicitl in the Tort Claims Act, Minnesota Stat

 STAT AUTH: MS s 116.07

 HIST: 18 SR 1059; 19 SR 1775; 20 SR 
Minnesota Rules, Chapter 7011. Current as of 04/12/00

 7011.0150 PREVENTING PARTICULATE MATTER FROM BECOMING AIRBORNE. 

 No person shall cause or permit the handling, use,  transporting, or storage of any material in a manner which may  allow avoidable amounts of particulate matter to become airborne.  No person shall cause or permit a building or its  appurtenances or a road, or a driveway, or an open area to be  constructed, used, repaired, or demolished without applying all  such reasonable measures as may be required to prevent  particulate matter from becoming airborne. All persons shall  take reasonable precautions to prevent the discharge of visible  fugitive dust emissions beyond the lot line of the property on  which the emissions originate. The commissioner may require  such reasonable measures as may be necessary to prevent  particulate matter from becoming airborne including, but not  limited to, paving or frequent clearing of roads, driveways, and  parking lots; application of dust-free surfaces; application of  water; and the planting and maintenance of vegetative ground  cover.  STAT AUTH: MS s 116.07

 HIST: L 1987 c 186 s 15; 18 SR 614; 20 SR 2316 

 7011.0610 STANDARDS OF PERFORMANCE FOR FOSSIL-FUEL-BURNING  DIRECT HEATING EQUIPMENT. 

 Subpart 1. Particulate limitations. Particulate  limitations:  A. No owner or operator of any direct heating  equipment shall cause to be discharged into the atmosphere from  the direct heating equipment any gases which:  (1) contain particulate matter in excess of the  limits allowed by parts 7011.0700 to 7011.0735; or  (2) exhibit greater than 20 percent opacity,  except for one six-minute period per hour of not more than 60  percent opacity. An exceedance of this opacity standard occurs  whenever any one-hour period contains two or more six-minute  periods during which the average opacity exceeds 20 percent or  whenever any one-hour period contains one or more six-minute  periods during which the average opacity exceeds 60 percent.  B. No owner or operator of an existing gray iron  cupola with a melting capacity of less than 1-1/2 tons per hour  shall allow emissions which exceed 0.3 grain per standard cubic  foot, dry basis, and the owner or operator shall incinerate all  gases, vapors, and gas entrained effluents from such cupolas at  a temperature of not less than 1,200 degrees Fahrenheit for a  period of not less than 0.3 seconds. The owner or operator of  any other gray iron cupola shall meet the requirements of item A.  Subp. 2. Sulfur oxide limitations. Sulfur oxide  limitations:  A. Within Minneapolis-Saint Paul Air Quality Control 

 Region. No owner or operator of direc located within the Minneapolis-Saint P Region shall cause to be discharged in such equipment any gases which contain  (1) in excess of three pounds p heat input if a solid fossil fuel is b million Btu heat input if a liquid fos total rated heat input of all indirect  equipment of the owner or operator at  exceeds 250 million Btu per hour;  (2) in excess of four pounds pe input if a solid fossil fuel is burned  Btu heat input if a liquid fossil fuel  rated heat input of all indirect and d the owner or operator at that particul less than 250 million Btu per hour.  B. Outside Minneapolis-Saint Pau Region. No owner or operator of direc located outside the Minneapolis-Saint  Region shall cause to be discharged in such equipment any gases which contain  of four pounds per million Btu heat in is burned or two pounds per million Bt fossil fuel is burned, if the total ra indirect and direct heating equipment  at that particular location is greater  hour.  STAT AUTH: MS s 116.07

 HIST: 18 SR 614; 23 SR 145 

 7011.0710 STANDARDS OF PERFORMANCE FO PROCESS EQUIPMENT. 

 Subpart 1. Prohibited discharge of  operator of any industrial process equ operation before July 9, 1969, shall c the atmosphere from the industrial pro which:  A. in any one hour contain parti excess of the amount permitted in part 

 allocated process weight; provided tha shall not be required to reduce the pa below the concentration permitted in p appropriate source gas volume; provide of the mass emission permitted by part  operator shall not be permitted to emi concentration in excess of 0.30 grains  of exhaust gas; or  B. exhibit greater than 20 perce for one six-minute period per hour of  opacity. An exceedance of this opacit any one-hour period contains two or mo during which the average opacity excee
 any one-hour period contains one or more six-minute periods 

 during which the average opacity exceeds 60 percent.  Subp. 2. Compliance. The owner or operator of any  industrial process equipment which was in operation before July  9, 1969, which has control equipment with a collection  efficiency of not less than 99 percent by weight shall be  considered in compliance with the requirements of subpart 1,  item A.  Subp. 3. Equipment located outside of Saint Paul,

Minneapolis, and Duluth. The owner or operator of any 

 industrial process equipment which was in operation before July  9, 1969, which is located outside the Minneapolis-Saint Paul Air  Quality Control Region and the city of Duluth, which is located  not less than one-fourth mile from any residence or public  roadway, and which has control equipment with a collection  efficiency of not less than 85 percent by weight, and the  operation of the entire emission facility does not cause a  violation of the ambient air quality standards, shall be  considered in compliance with the requirements of subpart 1,  item A.  STAT AUTH: MS s 116.07

 HIST: 18 SR 614; 23 SR 145 

 7011.0715 STANDARDS OF PERFORMANCE FOR POST-1969 INDUSTRIAL  PROCESS EQUIPMENT. 

 Subpart 1. Prohibited discharge of gases. No owner or  operator of any industrial process equipment which was not in  operation before July 9, 1969, shall cause to be discharged into  the atmosphere from the industrial process equipment any gases  which:  A. in any one hour contain particulate matter in  excess of the amount permitted in part 7011.0730 for the 

 allocated process weight; provided that the owner or operator  shall not be required to reduce the particulate matter emission  below the concentration permitted in part 7011.0735 for the 

 appropriate source gas volume; provided that regardless of the  mass emission permitted by part 7011.0730, the owner or operator 

 shall not be permitted to emit particulate matter in a  concentration in excess of 0.30 grains per standard cubic foot  of exhaust gas; or  B. exhibit greater than 20 percent opacity.  Subp. 2. Compliance. The owner or operator of any  industrial process equipment which was not in operation before  July 9, 1969, which has control equipment with a collection  efficiency of not less than 99.7 percent by weight shall be  considered in compliance with the requirements of subpart 1,  item A.  Subp. 3. Equipment located outside of Saint Paul,

Minneapolis, and Duluth. The owner or operator of any 

 industrial equipment which was in operation after July 9, 1969,  which is located outside the Minneapolis-Saint Paul Air Quality  Control Region and the city of Duluth, which is located not less 

 than one-fourth mile from any residenc which has control equipment with a col less than 85 percent by weight, and th emission facility does not cause a vio quality standards, shall be considered  requirements of subpart 1, item A.  STAT AUTH: MS s 116.07 subd 4  HIST: 18 SR 614 

 7011.1150 STANDARDS OF PERFORMANCE FO PLANTS. 

 Code of Federal Regulations, title  as amended, entitled "Standards of Per Preparation Plants," is adopted and in STAT AUTH: MS s 116.07 HIST: 18 SR 580 

 7011.2700 STANDARDS OF PERFORMANCE FO PROCESSING PLANTS. 

 Code of Federal Regulations, title  as amended, entitled "Standards of Per Mineral Processing Plants," is adopted  reference.  STAT AUTH: MS s 116.07 HIST: 18 SR 580 
ATTACHMENT P 

Applicable Michigan Air Regulations 
AIR POLLUTION CONTROL RULES 

PART 3. EMISSION LIMITATIONS AND 

PROHIBITIONS--PARTICULATE MATTER

As Amended March 19, 2002 

John Engler, Governor 

Russell J. Harding, Director 

Air Quality Division 

Michigan Department of Environmental Quality 

INTERNET: http://www.deq.state.mi.us 
R 336.1331 3-2 As Amended 3/19/2002 

MICHIGAN DEPARTMENT OF ENVIRONMENTAL QUALITY 

AIR QUALITY DIVISION 

As Amended March 19, 2002 

 PART 3. EMISSION LIMITATIONS AND PROHIBITIONS-- 

 PARTICULATE MATTER 

R 336.1301 Standards for density of emissions. 

 Rule 301. (1) Except as provided in subrules (2), (3), and (4) of this rule, a person shall 

not cause or permit to be discharged into the outer air from a process or process equipment a 

visible emission of a density greater than the most stringent of the following: 

 (a) A 6-minute average of 20% opacity, except for 1 6-minute average per hour of not 

more than 27% opacity. 

 (b) A limit specified by an applicable federal new source performance standard. 

 (c) A limit specified as a condition of a permit to install or permit to operate. 

 (2) The provisions of this rule shall not apply to any process or process equipment for 

which fugitive visible emission limitations are specified in any other administrative rule of 

the department. 

 (3) The provisions of subrule (1) of this rule shall not apply to visible emissions due to 

uncombined water vapor. 

 (4) Upon request by the owner of a process or process equipment for which an allowable 

particulate emission rate is established by R 336.1331, the department may establish an 

alternate opacity. Such alternate opacity shall not be established by the department unless 

the department is reasonably convinced of all of the following: 

 (a) That the process or process equipment subject to the alternate opacity is in 

compliance or on a legally enforceable schedule of compliance with the other rules of the 

department. 

 (b) That compliance with the provisions of subrule (1) of this rule is not technically or 

economically reasonable. 

 (c) That reasonable measures to reduce opacity have been implemented or will be 

implemented in accordance with a schedule approved by the department. 

History: 1979 ACS 1, Eff. Jan. 19, 1980; 1985 MR 2, Eff. Feb. 22, 1985; 2002 MR 5, Eff. Mar. 19, 

2002. 
R 336.1331 3-3 As Amended 3/19/2002 

R 336.1331 Emission of particulate matter. 

 Rule 331. (1) It is unlawful for a person to cause or allow the emission of particulate 

matter from any process or process equipment in excess of any of the following limits: 

 (a) The maximum allowable emission rate listed in table 31. 

 (b) The maximum allowable emission rate listed by the department on its own 

initiative or by application. A new listed value shall be based upon the control results 

achievable with the application of the best technically feasible, practical equipment 

available. This applies only to processes and process equipment not assigned a specific 

emission limit in table 31. 

 (c) The maximum allowable emission rate specified as a condition of a permit to install 

or a permit to operate. 

 (d) The maximum allowable emission rate specified in a voluntary agreement, 

performance contract, stipulation, or an order of the department. 

 (e) The maximum allowable emission rate as determined by table 32 for processes and 

process equipment not covered in subdivisions (a) to (d) of this subrule. 

 (2) Compliance with any emission limit required by this rule shall be determined by using 

the corresponding reference test method specified in table 31 or the reference test method 

deemed appropriate by the department for processes or process equipment not listed in 

table 31. 

 (3) Tables 31, 32, 33, 34, and figure 31 read as follows: 

History: 1979 ACS 1, Eff. Jan. 19, 1980; 1985 MR 2, Eff. Feb. 22, 1985; 1992 MR 9, Eff. Oct. 31, 

1992; 2002 MR 5, Eff. Mar. 19, 2002. 
TABLE 31 

Particulate matter emission schedule 

Process or process equipment Capacity rating for each 

unit 

Maximum allowable emission at opconditions1 (lbs. Particulate/1,000 lbs. gas excnoted) 

A. Fuel burning equipment  1. Pulverized coal  (includes cyclone furnaces) 

0-1,000,000 lbs. steam per hour. Over 1,000,000 lbs. Steam per hour 

See figure 31 for maximum emissioApply to department for specific emlimit. 

 2. Other modes of firing coal  (other than pulverized) 

0-100,000 lbs. steam per hour. 100,000-300,000 lbs.2 

steam per hour. Over 300,000 lbs. steam per hour. 

0.65 until superseded by A.3 and A0.65 - 0.45 Apply to department for specific emlimit. 

 3. Other modes of firing coal  (other than pulverized)  Existing fuel-burning equipment which is in a single structure and which has a combined coalfired existing capacity less than 250,000,000 Btu per hour. 

0-20,000,000 Btu per hour input. 20,000,001 to 100,000,000 Btu per hour input. Over 100,000,000 Btu per hour input 

0.65 effective immediately. 0.45 compliance shall be achieved expeditiously as practical, but not laJuly 1, 1981. 0.30 compliance shall be achieved expeditiously as practical, but not laDecember 31, 1982. 

 4. Other modes of firing coal  (other than pulverized)  Existing fuel-burning equipment which is in a single structure and which has a combined existing capacity equal to or greater than 250,000,000 Btu per hours. 

All sizes 0.30 compliance shall be achieved 

expeditiously as practical, but not laDecember 31, 1982. 
Process or process equipment Capacity rating for each 

unit 

Maximum allowable emission at operating conditions1 (lbs. particulate/1,000 lbs. gas eas noted) 

 5. Other modes of firing coal  (new processes or process equipment6) 

All sizes 0.10 

 6. Wood (sawdust, shavings, hogged, other) where heat input of wood fuel greater than 75% of total heat input.  All other combination fuel-burning equipment that uses wood as 1 of the fuels. 

 0.50 

Apply to department for specific emission limit. 

 7. Combination fuel-firing or combination fuel/waste-firing (new process or process equipment) 

All sizes Apply to department for specific 

emission limit. 

Rating in pounds waste per hour 

B. Incinerators  1. Residential apartments, commercial and industrial3, 4 0-100 

Over 100 

0.65 0.30 

 2. Municipal All 0.30  3. Pathological4 0.20  4. Manure drying or incineration4 0.20  5. Liquid waste incinerator 0.10 compliance shall be achiev

expeditiously as practical, but nothan December 31, 1982. 

 6. Sewage sludge incinerator 0.20 compliance shall be achiev

expeditiously as practical, but nothan December 31, 1982. 
Process or process equipment Capacity rating for each 

unit 

Maximum allowable emissoperating conditions1

(lbs. Particulate/1,000 lbs. gas 

as noted) 

C. Steel manufacturing  1. Basic oxygen furnaces  A. Primary control equipment12

 B. Secondary control equipment13 C. Primary control equipment if also used to control charging and tapping emissions 

0.05711

0.038110.05711

 2. Electric furnaces  A. Primary control equipment14

 B. Secondary control equipment15 C. Primary control equipment if also used to control charging and tapping emissions 

0.05711

0.010110.01011

 3. New sintering plants6

 A. Main windbox  B. Discharge 

0.06711

0.03811

 4. Existing sintering plants  A. Main windbox & discharge 0.12511  5. Blast furnaces  Blast furnace casthouse air cleaning device17

0.02 

 6. Coke oven combustion stacks 0.095  7. Coke oven push control equipment 0.10 lbs./ton of coke  8. Coke oven quench towers l,5009

or 1,50010

 9. Scarfing operations 0.05711 
Process or process equipment Total plant melt rate in 

tons/hour 

Maximum allowable emissoperating conditions1

(lbs. Particulate/1,000 lbs. gas 

as noted) 

D. Ferrous cupola foundry operations5 1. Existing production cupolas7 0-10 10-20 

Over 20 

0.40 0.25 0.15 

 2. Existing jobbing cupolas7 0.40  3. Electric arc melting 0.10  4. Sand handling 0.10  5. All new cupolas6 0-15 

Over 15 

1.8 - 0.72, 80.78

E. Chemical and mineral kilns 0.20 F. Asphalt paving plants  1. Located within a priority I or II area  (before January 1, 1980) 

 0.30 

 2. Located within a priority I or II area (after January 1, 1980) 

 0.10 

 3. Located outside priority I and II areas 0.30 G. Cement manufacture  1. Kiln - wet or dry process 0.25  2. Clinker coolers (before January 1, 1981)  (after January 1, 1981) 

 0.30 

0.10 

 3. Grinding, crushing, and other material handling. 

 0.15 
Process or process equipment Gas flow rate (SCFM) Maximum allowable emission at 

operating conditions1 (lbs. Particulate/1,000 lbs. gas eas noted) 

H. Iron ore pelletizing

 Grate kilns and traveling grates 

Over 600,000 300,000-600,000 100,000-300,000 0-100,000 

Apply to department for specific emission limit. 0.10 0.15 0.20 

I. Fertilizer plants (including ammoniator, granulator, reactor, dryer, cooler blender and all other processes

 Compliance shall be achieved as expeditiously as practical, but not later than January 1, 1981. 

0.10 

J. Exhaust systems serving material handling equipment not otherwise listed in table 31

 Compliance shall be achieved as expeditiously as practical, but not later than July 1, 1981. 

0.10 
Footnotes: 

1. Fuel burning and incineration limitation shall be calculated to 50% excess air. 2. Emission limitations for specific ratings are determined by linear interpolation between the ranges s3. These emission limitations do not apply to domestic incinerators (defined as having not more than 5 

storage capacity. 

4. Afterburner or approved equivalent is mandatory. 5. Differentiation between jobbing and production foundries. 

Cupolas used in a jobbing foundry are the same as those used in a production foundry and vary in to the quantity of iron melted per hour. However, the cupolas in a jobbing foundry are run intermittently just long enough at one time to pouare ready on the foundry floor, job by job. This might be for a 2- to 4-hour period per day for any nuweek. Production foundry cupolas melt continuously to pour a succession of molds that are constantly bereserve this continuous flow of iron. This could become 8 hours, 16 hours, or 24 hours per day for per week. 

6. New processes or process equipment are defined as those for which the permit to install was issue1980. 7. Any existing cupolas are considered to be in compliance with table 31 of R 336.1331 if they meet th

emission limit for new cupolas. 

8. Pounds of particulate per ton of charged material. 9. Milligrams per liter of total dissolved solids in the quench water. 10. Milligrams per liter of total dissolved solids in the make-up water. 11. Compliance shall be determined by means of a comparison between the emission limit and the me

rate calculated on a dry basis (pounds particulate per 1,000 pounds dry gas). 

12. "Primary control equipment", as applied to basic oxygen furnaces, means the control equipment de

and control particulate emissions during oxygen blowing. 

13. "Secondary control equipment", as applied to basic oxygen furnaces, means the control equipment 

capture and control particulate emissions during process steps other than oxygen blowing. 

14. "Primary control equipment", as applied to electric furnaces, means the control equipment designed 

control particulate emissions during meltdown and refining. 

15. "Secondary control equipment", as applied to electric furnaces, means the control equipment desig

control particulate emissions during process steps other than meltdown and refining. 
16. "Standard Methods for the Examination of Water and Wastewater" (14th edition) section 208C, as 

336.2033, shall be used as the applicable test method. 

17. The mass emission limit specified is not applicable where fume suppression technology, approved 

is used to control blast furnace casthouse emissions. 
R 336.1367 3-11 As Amended 3/19/2002 

TABLE 32 

Allowable rate of emission based on process weight ratea

Process weight rate Rate of 

Emission 

Process weight rate Rate of 

emission 

Lb/hr Tons/hr Lb/hr Lb/hr Tons/hr Lb/hr 

100 0.05 0.55 16,000 8.0 16.5 

200 0.10 0.88 18,000 9.0 17.9 

400 0.20 1.40 20,000 10.0 19.2 

600 0.30 1.83 30,000 15.0 25.2 

800 0.40 2.22 40,000 20.0 30.5 

1,000 0.50 2.58 50,000 25.0 35.4 

1,500 0.75 3.38 60,000 30.0 40.0 

2,000 1.00 4.10 70,000 35.0 41.3 

2,500 1.25 4.76 80,000 40.0 42.5 

3,000 1.50 5.38 90,000 45.0 43.6 

3,500 1.75 5.95 100,000 50.0 44.6 

4,000 2.00 6.52 120,000 60.0 46.3 

5,000 2.50 7.58 140,000 70.0 47.8 

6,000 3.00 8.56 160,000 80.0 49.0 

7,000 3.50 9.49 200,000 100.0 51.2 

8,000 4.00 10.40 1,000,000 500.0 69.0 

9,000 4.50 11.20 2,000,000 1,000.0 77.6 

10,000 5.00 12.00 6,000,000 3,000.0 92.7 

12,000 6.00 13.60 

a

 Interpolation of the data in this table for process weight rates up to 60,000 lb/hr 

shall be accomplished by use of the equation E = 4.10 P0.67 and interpolation and 

extrapolation of the data for process weight rates in excess of 60,000 lb/hr shall be 

accomplished by use of the equation E = 55.0 P0.11 - 40, where E = rate of emission 

in lb/hr and P = process weight in tons/hr. 

Process weight -- The total amount of all material introduced into a process, 

including solid fuels, but excluding liquid fuels and gaseous fuels when these are 

used as fuels and air introduced for purposes of combustion. 

Process weight rate -- For continuous or long-term operation: The total process 

weight for the entire period of operation or for a typical portion thereof, divided by the 

number of hours of such period or portion thereof. For batch operations: The total 

process weight for a period which covers a complete operation or an integral number 

of cycles, divided by the hours of actual process operation during such period. 
R 336.1367 3-12 As Amended 3/19/2002 

TABLE 33 

Priority I areas 

County Area

Calhoun T2S, R4W, Section 34. 

Genesee Starting on Industrial Avenue, north to Stewart Avenue, east to Hitchcock 

Street, south to Olive Avenue (extended), south to Robert T. Longway 

Boulevard, west and southwest to Industrial Avenue. 

Lapeer T7N, R12E, that portion of Section 17 which lies south of M-21 and east of 

Fairground Road. 

Monroe Starting where Sandy Creek empties into Lake Erie, northwest to Maple 

Avenue (extended north-northeast), southwest to Elm Avenue, west to Herr 

Road, south to Dunbar Road and east to Plum Creek (which empties into 

Lake Erie). 

Saginaw Starting at Tittabawassee Road, east to I-75, east and south to Washington 

Avenue, west to 6th Street, north to Carrolton Street, northeast to Zilwaukee 

Street, north to Westervelt Street, north to Tittabawassee Road. 

Wayne Area included within the following (counter clockwise): Lake St. Clair to 

Moross Road to Seven Mile Road to VanDyke Road to Eight Mile Road to 

Wyoming Road to Seven Mile Road to Schaeffer Road to Fenkell Road to 

Greenfield Avenue to Joy Road to Southfield Expressway to Ford Road to 

Telegraph Road to Cherry Hill Road to Beech-Daly Road (extended) to 

Michigan Avenue to Inkster Road to Carlysle Street to Middle Belt Road to 

Vanborn Road to Wayne Road to Pennsylvania Road to Middle Belt Road 

to Sibley Road to Telegraph Road to King Road to Grange Road to Sibley 

Road to Jefferson Avenue to Bridge Street (Grosse Ile) extended to Detroit 

River. 
R 336.1367 3-13 As Amended 3/19/2002 

TABLE 34 

Priority II areas 

County Area

Bay T14N, R5E, Sections 14 to16 and 21 to 23. 

Delta T39N, R22W, Sections 19, 30, south one-half of 17, and south one-half of 

18. 

Genesee Starting on Industrial Avenue, north to Pierson Road, east to Dort 

Highway, south to Hitchcock Street, south to Olive Avenue (extended), 

south to Robert T. Longway Boulevard, west and southwest to Industrial 

Avenue. 

Macomb T4N, R14E, Sections 27, 28, 33, and 34. 

Manistee T21N, R16W, Sections 7,18, and 19; 

 T21N, R17W, Sections 12 and 13. 

Midland T14N, R2E, Sections 14 to 16, 21 to 23, 26 to 28, and 33 to 35. 

Monroe T5S, RIOE, Sections 8, 9, and 15 to 17. 

Muskegon T9N, R16W, Sections 5 and 6; 

 T1ON, R16W, Sections 21, 22, and 27 to 34. 

Saginaw Northeast section: starting on Tittabawassee Road, east to I-75, south to 

Wadsworth Avenue, west to I-675, west and north to Tittabawassee Road. 

 Southwest section: T12N, R4E, the eastern half of Section 34 (that which 

is east of Maple Street) and Section 35. 

St. Clair T6N, R17E, Sections 2 to 4, 9 to 11, 14 to 16, 21, 22, and 28. 

Wayne The area included within the following (counter clockwise): Lake St. Clair to 

Eight Mile Road to Schaeffer Road to McNichols Road to Greenfield Avenue to 

Schoolcraft Avenue to Evergreen Road to Joy Road to Telegraph Road to Ford Road 

to Beech-Daly Road to Cherry Hill Road to Inkster Road to Carlysle Street to Middle 

Belt Road to VanBorn Road to Wayne Road to Ecorse Road to Haggerty Highway to 

Tyler Road to Belleville Road to I-94 to Rawsonville Road to Oakville Waltz Road to 

Will Carleton Road to the Huron River to Lake Erie, except subarea listed in table 33.
R 336.1372 3-14 As Amended 3/19/2002 

R 336.1370 Collected air contaminants. 

 Rule 370. (1) Collected air contaminants shall be removed as necessary to maintain the 

equipment at the required operating efficiency. The collection and disposal of air 

contaminants shall be performed in a manner so as to minimize the introduction of 

contaminants to the outer air. 

 (2) At a minimum, in priority I and II areas listed in tables 33 and 34, the use of 1 or more 

of the following material handling methods is required for the transport of collected air 

contaminants: 

 (a) Enclosed trucking or transporting vehicles. 

 (b) Enclosed, pneumatic, or screw conveying transporting equipment. 

 (c) Water or dust suppressant sprays. 

 (d) An acceptable method which is equivalent to the methods listed in subdivisions (a), 

(b), and (c) of this subrule. 

History: 1979 ACS 5, Eff. Feb. 18, 1981. 

R 336.1371 Fugitive dust control programs other than areas listed in table 36. 

 Rule 37l. (l) Based on ambient air quality measurements or substantive complaints, the 

department may request that the person who is responsible for the operation of any facility 

which processes, uses, stores, transports, or conveys bulk materials, such as, but not limited 

to, coal, coke, metal ores, limestone, cement, sand, gravel, and material from air pollution 

control devices, or a facility which has activities specifically identified in R 336.l372 and 

which facility is in an area not listed in table 36, submit a fugitive dust control program. The 

department shall notify the person who is responsible for the operation of the facility of the 

provisions of R 336.l372 which apply to the facility and the reasons for the department’s 

notification. Except as provided in subrule (3) of this rule, the control program shall be 

submitted to the department not later than 6 months after notification. 

 (2) A fugitive dust control program which is required by subrule (l) of this rule shall be in 

writing and shall provide for all of the following: 

 (a) Using l or more combinations of available technologies, operating practices, or 

methods listed in R 336.l372 as are reasonably necessary to control fugitive dust 

emissions. 

 (b) Consideration of the quantity, moisture content, specific gravity, and the particle 

size distribution of the bulk materials. The more friable, drier, lighter, and finer the bulk 

material is, the more effective the fugitive dust control methods incorporated into the 

control program shall be. 

 (c) The keeping and maintenance of records consistent with the various activities to be 

implemented under the control program. 
R 336.1372 3-15 As Amended 3/19/2002 

 (d) Identification of the control technologies, methods, or control equipment, if any, to 

be implemented or installed and the schedule, including increments of progress, for 

implementation or installation. 

 (3) Within 3 months following notification by the department that a fugitive dust control 

program is required, the person who is responsible for operating the facility has the 

opportunity to demonstrate, to the satisfaction of the department, that any part of the facility 

is not subject to the provisions of this rule. 

 (4) If a control program is not submitted within 6 months after notification by the 

department, then the department may proceed, pursuant to the act, toward the entry of a final 

order which contains a control program that meets the requirements of subrule (2) of this 

rule. 

 (5) The control program is subject to review and approval by the department. The 

department shall approve a control program only upon the entry of a legally enforceable 

order or as part of an approved permit to install or operate. If, in the opinion of the 

department, the program does not adequately meet the requirements set forth in subrule (2) of 

this rule, then the department may disapprove the program, state its reasons for disapproval, 

and require the preparation and submittal of an amended program within a specified time 

period. If, within the specified time period, an amended program is either not submitted or is 

submitted but, in the opinion of the department, fails to meet the requirements of subrule (2) 

of this rule, then the department may proceed, pursuant to the act, toward the entry of a final 

order which contains a control program that meets these requirements. 

 (6) After approval by the department, the person who is responsible for the preparation of 

the control program shall begin implementation of the program pursuant to the schedule 

contained in the control program. 

 (7) Either the person who is responsible for a facility or the department may request a 

revision to a department-approved control program to meet changing conditions. The 

department shall review the revision following the requirements of subrule (5) of this rule. 

 (8) Table 36 reads as follows: 
R 336.1372 3-16 As Amended 3/19/2002 

TABLE 36 

County Area

Bay T14N, R5E, Sections 14 to 16 and 21 to 23. 

Calhoun T2S, R4W, Section 34. 

Delta T39N, R22W, Sections 19, 30, south one-half of 17, and south one-half of 18. 

Genesee Starting on Industrial Avenue, north to Pierson Road, east to Dort Highway, south 

to Hitchcock Street, south to Olive Avenue (extended), south to Robert T. Longway 

Boulevard, west and southwest to Industrial Avenue. 

Lapeer T7N, R12E, that portion of Section 17 which lies south of M-21 and east of 

Fairground Road. 

Macomb T4N, R14E, Sections 27, 28, 33, and 34. 

Manistee T21N, R16W, Sections 7, 18, and 19; 

 T21N, R17W, Sections 12 and 13. 

Midland T14N, R2E, Sections 14 to 16, 21 to 23, 26 to 28, and 33 to 35. 

Monroe Starting where Sandy Creek empties into Lake Erie, northwest to Maple Avenue 

(extended north-northeast), southwest to Elm Avenue, west to Herr Road, south to 

Dunbar Road and east to Plum Creek (which empties into Lake Erie). 

Muskegon T9N, R16W, Sections 5 and 6; 

 T10N, R16W, Sections 21, 22, and 27 to 34. 

Saginaw Northeast section: starting on Tittabawassee Road, east to I-75, south to 

Wadsworth Avenue, west to I-675, west and north to Tittabawassee Road. 

 Southwest section: T12N, R4E, the eastern half of Section 34 (that which is east of 

Maple Street) and Section 35. 

St. Clair T6N, R17E, Sections 2 to 4, 9 to 11, 14 to 16, 21, 22, and 28. 

Wayne Area included within the following (counter clockwise): Lake St. Clair to Moross 

Road to Seven Mile Road to Vandyke Road to Eight Mile Road to Wyoming Road 

to Seven Mile Road to Schaeffer Road to Fenkell Road to Greenfield Avenue to 

Joy Road to Southfield Expressway to Ford Road to Telegraph Road to Cherry Hill 

Road to Beech-Daly Road (extended) to Michigan Avenue to Inkster Road to 

Carlysle Street to Middle Belt Road to Vanborn Road to Wayne Road to 

Pennsylvania Road to Middle Belt Road to Sibley Road to Telegraph Road to King 

Road to Grange Road to Sibley Road to Jefferson Avenue to Bridge Street (Grosse 

Ile) extended to Detroit River. Also included is that portion of the City of Riverview 

which is south of Sibley Road and the City of Trenton. 
R 336.1372 3-17 As Amended 3/19/2002 

History: 1979 ACS 5, Eff. Feb. 18, 1981; 1985 MR 4, Eff. Apr. 23, 1985; 2002 MR 5, Eff. Mar. 19, 

2002. 
R 336.1372 3-18 As Amended 3/19/2002 

R 336.1372 Fugitive dust control program; required activities; typical control methods. 

 Rule 372. (1) A fugitive dust control program which is required by R 336.1371 and 

which deals with 1 or more of the fugitive dust sources listed in this rule may include any of 

the typical control methods listed in this rule for that source. 

 (2) The following provisions apply to the loading or unloading of open storage piles of 

bulk materials as a source of fugitive dust: 

 (a) Open storage piles of bulk materials, hereinafter referred to as "piles", which meet 

any of the following 3 conditions need not be included in a fugitive dust control program: 

 (i) All piles of the same material at a manufacturing or commercial location which 

have a total volume of less than 100 cubic meters (131 yards3). 

 (ii) Any piles at a manufacturing or commercial location if the total annual 

volumetric throughput of all the stored material at the site is less than 10,000 cubic 

meters (13,100 yards3

). 

 (iii) Any single pile at a manufacturing or commercial location that has a volume 

of less than 42 cubic meters (55 yards3). 

 (b) Typical control methods for controlling fugitive emissions resulting from the 

loading or unloading of piles may include, but are not limited to, the following: 

 (i) Completely enclosing the pile within a building furnished with departmentapproved air pollution control equipment. 

 (ii) Using pneumatic conveying or telescopic chutes. 

 (iii) Spraying the working surface of the pile with water or dust-suppressant 

compound. 

 (iv) Directing engine exhaust gases that are generated by the machine used on the 

piles for loading or unloading upwards. 

 (v) Minimizing the drop distance from which the material is discharged into the 

pile. The drop distance shall be specified in the control program. 

 (vi) Periodic removal of spilled material in areas within 100 meters (328 feet) from 

the pile. The frequency of removal shall be specified in the control program. 

 (3) All of the following provisions apply to the transporting of bulk materials as a source 

of fugitive dust: 

 (a) Trucks which have less than a 2-ton capacity that are used to transport sand, gravel, 

stones, peat, and topsoil are exempt from the provisions of this subrule. 

 (b) Typical control methods for controlling fugitive emissions resulting from the 

transporting of bulk materials by truck may include, but are not limited to, the following: 

 (i) Completely covering open-bodied trucks. 

 (ii) Cleaning the wheels and the body of each truck to remove spilled materials 

after the truck has been loaded. 
R 336.1372 3-19 As Amended 3/19/2002 

 (iii) Use of completely enclosed trucks. 

 (iv) Tarping the truck when operating empty if residue has not been completely 

removed after emptying. 

 (v) Cleaning the residue from the inside of the truck after emptying. 

 (vi) Loading trucks so that no part of the load making contact with any sideboard, 

side panel, or rear part of the load enclosure comes within 6 inches of the top part of 

the enclosure. 

 (vii) Maintaining tight truck bodies so that leakages within the body will be 

eliminated and future leakages prevented. 

 (viii) Spraying the material being transported in a vehicle with a dust suppressant. 

The frequency of spraying shall be specified in the control program. 

 (ix) Restricting the speed of the vehicle which transports the material. The speed of 

the vehicle shall be specified in the control program. 

 (4) The following provision applies to outdoor conveying as a source of fugitive dust: 

Typical control methods for controlling fugitive emissions resulting from conveying bulk 

materials may include, but are not limited to, the following: 

 (a) Completely enclosing all conveyor belts and equipping them with belt wipers and 

hoppers of proper size to prevent excessive spills. 

 (b) Enclosing transfer points and, if necessary, exhausting them to a baghouse or 

similar control device at all times when the conveyors are in operation. 

 (c) Equipping the conveyor belt with not less than 210-degree enclosures. 

 (d) Restricting the speed of conveyor belts. The belt speed shall be specified in the 

control program. 

 (e) Periodically cleaning the conveyor belt to remove the residual material. The 

frequency of cleaning shall be specified in the control program. 

 (f) Minimizing the distance between transfer points. The distance between transfer 

points shall be specified in the control program. 

 (g) Removing the spilled material from the ground under conveyors. The frequency of 

removal shall be specified in the control program. 

 (5) The following provisions apply to roads and lots as sources of fugitive dust: 

 (a) Roads and lots which are located within industrial, commercial, and governmentowned facilities and which meet the following 2 conditions are not subject to the 

requirement of submitting a fugitive dust control program: 

 (i) The traffic volume is less than 10 vehicles per day on a monthly average. 

 (ii) The lots are less than 500 square meters (5,382 feet2

) in area. 

 (b) Typical control methods for controlling fugitive emissions resulting from roads and 

lots located within industrial, commercial, and government-owned facilities may include, 

but are not limited to, the following: 
R 336.1372 3-20 As Amended 3/19/2002 

 (i) Paving roads and parking lots with a hard material, such as concrete, asphalt, or 

an equivalent which is approved by the department. 

 (ii) Mechanically cleaning paved surfaces by vacuum sweeping, wet sweeping, or 

flushing. The frequency of cleaning shall be specified in the control program. 

 (iii) Washing the wheels of every truck leaving the plant premises. 

 (iv) Treating the roads and lots with oil or a dust-suppressant compound which is 

approved by the department. The frequency of application shall be specified in the 

control program. 

 (v) Periodically maintaining off-road surfaces with gravel where trucks have 

frequent access. The frequency of maintenance shall be specified in the control 

program. 

 (6) The following provisions apply to inactive storage piles as sources of fugitive dust: 

 (a) Inactive storage piles that are less than or equal to 500 cubic meters (654 yards3

) in 

volume are not subject to the requirement of submitting a fugitive dust control program. 

 (b) Typical control methods for controlling fugitive emissions resulting from inactive 

storage piles may include, but are not limited to, the following: 

 (i) Completely covering the pile with tarpaulin or other material approved by the 

department. 

 (ii) Completely enclosing the pile within a building. 

 (iii) Enclosing the pile with not less than 3 walls so that no portion of the stored 

material is higher than the walls. 

 (iv) Periodically spraying the piles with water or other dust-suppressant compound 

approved by the department. The frequency of application shall be specified in the 

control program. 

 (v) Growing vegetation on and around the pile. 

 (7) The following provisions apply to building ventilation as a source of fugitive dust: 

 (a) This subrule is applicable to all of the following: 

 (i) Ferrous and nonferrous foundries. 

 (ii) Electric arc furnaces, blast furnace casthouses, sinter plants, and basic oxygen 

processes at iron and steel production facilities. 

 (iii) Metal heat treating. 

 (iv) Metal forging. 

 (v) Bulk material handling, storage, drying, screening, and crushing. 

 (vi) Metal fabricating and welding. 

 (vii) Briquetting, sintering, and pelletizing operations. 

 (viii) Machining and pressing of metal. 
R 336.1372 3-21 As Amended 3/19/2002 

 (ix) Stone, clay, and glass production. 

 (x) Lime, cement, and gypsum production. 

 (xi) Chemical and allied product production. 

 (xii) Asphalt and concrete mixing operations. 

 (b) Typical control methods for controlling fugitive emissions resulting from building 

openings, such as roof monitors, powered and unpowered ventilators, doors, windows, and 

holes in the building structure integrity, may include, but are not limited to, the following: 

 (i) Exhausting the entire building to a dust collection system which is acceptable to 

the department. 

 (ii) Using local hoods connected to a dust collection system to capture emissions 

within the building. 

 (iii) Establishing and maintaining operating procedures and internal housekeeping 

practices (specify details). 

 (iv) Installing removable filter media across the vent openings. 

 (8) The following provisions apply to fugitive dust emissions from construction, 

renovation, or demolition activities located in priority I areas: 

 (a) This subrule is applicable to the owner or prime contractor, except for those owners 

or prime contractors who construct, renovate, or demolish less than 12 single-family 

dwelling units per year. 

 (b) Typical control methods for controlling fugitive dust emissions from construction, 

renovation, or demolition activities may include, but are not limited to, the following: 

 (i) Spraying of all work areas with water or other dust-suppressant compound 

which is approved by the department. 

 (ii) Completely covering the debris, excavated earth, or other airborne materials 

with tarpaulin or any other material which is approved by the department. 

 (iii) Any other method acceptable to the department. 

History: 1979 ACS 5, Eff. Feb. 18, 1981; 2002 MR 5, Eff. Mar. 19, 2002. 
AIR POLLUTION CONTROL RULES 

PART 4. EMISSION LIMITATIONS AND PROHIBITIONS - 

SULFUR-BEARING COMPOUNDS 

As Amended March 19, 2002 

John Engler, Governor 

Russell J. Harding, Director 

Air Quality Division 

Michigan Department of Environmental Quality 

INTERNET: http://www.michigan.gov
MICHIGAN DEPARTMENT OF ENVIRONMENTAL QUALITY 

AIR QUALITY DIVISION 

As Amended March 19, 2002 

 PART 4. EMISSION LIMITATIONS AND PROHIBITIONS - SULFUR-BEARING 

COMPOUNDS 

R 336.1402 Emission of sulfur dioxide from fuel-burning sources other than power 

plants. 

 Rule 402. (1) Except as provided in rule 401 and subrule (2), after January 1, 1981, it is 

unlawful for a person to cause or allow the emission of sulfur dioxide from the combustion 

of any coal or oil fuel in excess of 1.7 pounds per million Btu's of heat input for oil fuel or in 

excess of 2.4 pounds per million Btu's of heat input for coal fuel. 

 (2) The provisions of this rule do not apply to a fuel-burning source that is unable to 

comply with the specified emission limits because of sulfur dioxide emissions caused by the 

presence of sulfur in other raw materials charged to the fuel-burning source. This exception 

shall apply if at any time the actual sulfur dioxide emission rate exceeds the expected 

theoretical sulfur dioxide emission rate from fuel burning. The expected theoretical sulfur 

dioxide emission rate shall be based on the quantity of fuel burned and the average sulfur 

content of the fuel. 

History: 1979 ACS 1, Eff. Jan. 19, 1980. 
AIR POLLUTION CONTROL RULES 

PART 7. EMISSION LIMITATIONS AND 

PROHIBITIONS--NEW SOURCES OF VOLATILE 

ORGANIC COMPOUND EMISSIONS 

As Amended March 19, 2002 

John Engler, Governor 

Russell J. Harding, Director 

Air Quality Division 

Michigan Department of Environmental Quality 

INTERNET: http://michigan.gov 

MICHIGAN DEPARTMENT OF ENVIRONMENTAL QUALITY 

AIR QUALITY DIVISION 

As Amended March 19, 2002 

 PART 7. EMISSION LIMITATIONS AND PROHIBITIONS-- 

 NEW SOURCES OF VOLATILE ORGANIC COMPOUND EMISSIONS 

R 336.1702 New sources of volatile organic compound emissions generally. 

 Rule 702. A person who is responsible for any new source of volatile organic compound 

emissions shall not cause or allow the emission of volatile organic compound emissions from 

the new source in excess of the lowest maximum allowable emission rate of the following: 

 (a) The maximum allowable emission rate listed by the department on its own 

initiative or based upon the application of the best available control technology. 

 (b) The maximum allowable emission rate specified by a new source performance 

standard promulgated by the United States environmental protection agency under 

authority enacted by title I, part A, section 111 of the clean air act, as amended, 42 U.S.C. 

§7413. 

 (c) The maximum allowable emission rate specified as a condition of a permit to install 

or a permit to operate. 

 (d) The maximum allowable emission rate specified in part 6 of these rules which 

would otherwise be applicable to the new source except for the date that the process or 

process equipment was placed into operation or for which an application for a permit to 

install, under the provisions of part 2 of these rules, was made to the department. If the 

part 6 allowable emission rate provides for a future compliance date, then the future 

compliance date shall also be applicable to a new source pursuant to this subdivision. 

History: 1979 ACS 1, Eff. Jan. 19, 1980; 1993 MR 4, Eff. Apr. 28, 1993; 2002 MR 5, Eff. Mar. 19, 

2002. 
AIR POLLUTION CONTROL RULES 

PART 8. EMISSION LIMITATIONS AND 

PROHIBITIONS—OXIDES OF NITROGEN 

As Amended December 4, 2002 

Jennifer M. Granholm, Governor 

Steven E. Chester, Director 

Air Quality Division 

Michigan Department of Environmental Quality 

INTERNET: http://www.michigan.gov
R 336.1801 8-2 As Amended December 4, 2002 

MICHIGAN DEPARTMENT OF ENVIRONMENTAL QUALITY 

AIR QUALITY DIVISION 

As Amended December 4, 2002 

PART 8. EMISSION LIMITATIONS AND PROHIBITIONS— 

OXIDES OF NITROGEN 

R 336.1801 Emission of oxides of nitrogen from non-sip call stationary sources. 

 Rule 801. (1) As used in this rule: 

 (a) "Capacity factor" means either of the following: 

 (i) The ratio of a unit's actual annual electric output, expressed in megawatt hour, 

to the unit's nameplate capacity times 8,760 hours. 

 (ii) The ratio of a unit's annual heat input, expressed in million British thermal 

units or equivalent units of measure, to the unit's maximum design heat input, 

expressed in million British thermal units per hour or equivalent units of measure, 

times 8,760 hours. 

 (b) “Fossil fuel-fired” means the combustion of fossil fuel, alone or in combination 

with any other fuel, where the fossil fuel actually combusted comprises more than 50% of 

the fuel mass or annual heat input on a British thermal unit basis. Coke oven gas is a fossil 

fuel. 

 (c) "Low-NOx burners" means 1 of several developing combustion technologies used 

to minimize the formation of emissions of nitrogen oxides. As applicable to cement kilns, 

low-NOx burners means a type of cement kiln burner system designed to minimize NOx

formation by controlling flame turbulence, delaying fuel/air mixing, and establishing fuelrich zones for initial combusting, that for firing of solid fuel in the burning end zone of a 

kiln's main burner includes an indirect firing system or comparable technique for the main 

burner in the burning end zone of the kiln to minimize the amount of primary air supplied 

through the burner. In an indirect firing system, 1 air stream is used to convey pulverized 

fuel from the grinding equipment and at least 1 or more other air streams are used to 

supply primary air to the burning end zone kiln burner of the kiln with the pulverized fuel, 

with intermediate storage of the fuel, and necessary safety and explosion prevention 

systems associated with the intermediate storage of fuel. 

 (d) "Mid-kiln system firing" means the secondary firing in a kiln system by injecting 

solid fuel at an intermediate point in the kiln system using a specially designed heat 

injection mechanism for the purpose of decreasing NOx emissions through coal burning 

part of the fuel at lower temperatures and reducing conditions at the fuel injection point 

that may destroy some of the NOx. 
R 336.1801 8-3 As Amended December 4, 2002 

 (e) “Non-sip call source” means any stationary source of oxides of nitrogen emissions 

that is not defined as an oxide of nitrogen budget source in R 336.1803. 

 (f) “Ozone control period” means the period of May 31, 2004, through September 30, 

2004, and the period of May 1 through September 30 each subsequent and prior year. 

 (g) "Peaking unit" means a unit that has an average capacity factor of not more than 

10% during the previous 3 calendar years and a capacity factor of not more than 20% in 

each of those calendar years. 

 (h) “Process heater” means any combustion equipment which is fired by a liquid fuel 

or a gaseous fuel, or both, and which is used to transfer heat from the combustion gases to 

a process fluid, superheated steam, or water. 

 (i) “Unit” means a fossil fuel-fired combustion device. 

 (j) “Utility system” means all interconnected units and generators which are subject to 

subrule (2) of this rule and which are operated by the same utility operating company or by 

common ownership and control. 

 (2) An owner or operator of a fossil fuel-fired, electricity-generating utility unit which has 

the potential to emit more than 25 tons each ozone control period of oxides of nitrogen and 

which serves a generator that has a nameplate capacity of 25 megawatts or more shall 

comply with the emission limits during the ozone control period as follows: 

 (a) By May 31, 2004, meet the least stringent of a utility system-wide average oxides 

of nitrogen emission rate of 0.25 pounds per million British thermal units heat input or an 

emission rate based on a 65% reduction of oxides of nitrogen from 1990 levels. 

 (b) The date listed in subdivision (a) of this subrule may be extended by up to 2 years 

if an owner or operator makes an acceptable demonstration to the department that the 

additional time is necessary to avoid disruption of the energy supply in the state or if the 

additional time is necessary to comply with the provisions of this rule. 

 (3) An owner or operator shall demonstrate compliance with the emission limits in 

subrule (2) of this rule as follows: 

 (a) To demonstrate compliance with a utility system-wide average emission rate, the 

owner or operator shall show that the sum of the mass emissions from all units owned or 

operated by a utility that is subject to subrule (2) of this rule which occurred during the 

ozone control period, divided by the sum of the heat input from all units owned or 

operated by a utility that is subject to subrule (2) of this rule which occurred during the 

ozone control period is less than or equal to the limits in subrule (2) of this rule. 

 (b) To demonstrate compliance with the percent reduction requirements of subrule (2) 

of this rule, the owner or operator shall provide calculations showing that the utility 

system average emission rate during each compliance ozone control period has been 

reduced below the 1990 ozone control period average emission rate by the applicable 

percent reduction listed in subrule (2) of this rule. The 1990 ozone control period average 

emission rate is the sum of the mass emissions from all units owned or operated by a 

utility that is subject to subrule (2) of this rule which occurred during the 1990 ozone 

control period divided by the sum of the heat input from all units owned or operated by a 
R 336.1801 8-4 As Amended December 4, 2002 

utility that is subject to subrule (2) of this rule which occurred during the 1990 ozone 

control period. 

 (4) By May 31, 2004, an owner or operator of a fossil fuel-fired emission unit which has 

the potential to emit more than 25 tons of oxides of nitrogen each ozone control period, 

except for an emission unit that is subject to subrule (2) of this rule, and which has a 

maximum rated heat input capacity of more than 250 million British thermal units per hour 

shall comply with the following provisions, as applicable: 

 (a) An owner or operator of a fossil fuel-fired, electricity-generating utility unit which 

serves a generator that has a nameplate capacity of less than 25 megawatts which has a 

maximum rated heat input capacity of more than 250 million British thermal units per hour 

shall comply with the appropriate oxides of nitrogen emission limit in table 81 of this rule. 

 (b) An owner or operator of a fossil fuel-fired boiler or process heater shall meet the 

emission limits contained in table 81 of this rule. 

 (c) An owner or operator of a gas-fired boiler or process heater that fires gaseous fuel 

which contains more than 50% hydrogen by volume shall comply with an oxide of 

nitrogen emission limit of 0.25 pounds per million Btu heat input. 

 (d) An owner or operator of a stationary internal combustion engine which is subject to 

the provisions of this rule and which has a maximum rated heat input capacity that is the 

heat input at 80 degrees Fahrenheit at sea level and takes into account inlet and exhaust 

losses shall comply with the following oxides of nitrogen emission limits, as applicable: 

 (i) For a natural gas-fired stationary internal combustion engine - 14 grams of 

oxides of nitrogen per brake horsepower hour at rated output. 

 (ii) For a diesel-fired stationary internal combustion engine - 10 grams of oxides of 

nitrogen per brake horsepower hour at rated output. 

 (e) An owner or operator of a cement kiln that is subject to the provisions of this rule 

shall reduce kiln oxides of nitrogen emissions by any of the following methods: 

 (i) Low oxides of nitrogen burners. 

 (ii) Mid-kiln system firing. 

 (iii) A 25% rate-based reduction of oxides of nitrogen from 1995 levels. 

Compliance with this paragraph shall be based on calculations showing that the 

emission rate, on a pounds of oxides of nitrogen per ton of clinker produced basis, 

during each compliance ozone control period, has been reduced below the 1995 ozone 

control period emission rate by 25%. 

 (f) An owner or operator of a stationary gas turbine which is subject to the provisions 

of this rule and which has a maximum rated heat input capacity that is the heat input at 80 

degrees Fahrenheit at sea level and takes into account inlet and exhaust losses shall 

comply with an emission limit of 75 parts per million, dry volume, corrected to 15% 

oxygen, at rated capacity. The provisions of this rule do not apply to a stationary gas 

turbine that is subject to a new source performance standard contained in 40 C.F.R. part 

60, subpart gg (2001), which is adopted by reference in subrule (7) of this rule. 
R 336.1801 8-5 As Amended December 4, 2002 

 (g) An owner or operator of an emission unit which is subject to this rule and which is 

not otherwise subject to the provisions of subdivisions (a) to (f) of this subrule shall 

submit a proposal for oxides of nitrogen control by November 17, 2000. An owner or 

operator shall implement the control program by May 31, 2004, or by an alternate date 

approved by the department. The owner or operator shall obtain department approval of 

the proposed control program. The proposal for oxides of nitrogen control shall include 

all of the following information: 

 (i) A listing of reasonably available oxides of nitrogen control technologies, 

including the costs of installation and operation, cost of control per ton of oxides of 

nitrogen reduced, and the projected effectiveness of the proposed control technologies. 

The owner or operator shall use costing methodologies acceptable to the department. 

 (ii) The technology selected for controlling oxides of nitrogen emissions from the 

emission unit, considering technological and economic feasibility. 

 (iii) A proposal for testing, monitoring, and reporting oxides of nitrogen emissions. 

 (h) The compliance date listed in this subrule may be extended by up to 2 years if an 

owner or operator makes an acceptable demonstration to the department that the additional 

time is necessary to comply with the provisions of this rule. The owner or operator of a 

unit subject to subrules (2) and 4(a) to (f) of this rule may request an alternate emission 

limit or control requirement if there is an acceptable demonstration made to the 

department that compliance with the limits in table 81, or other limits or control 

requirements, is not reasonable. The request for an alternate emission limit or control 

requirement shall be submitted to the department within 60 days of the effective date of 

this amendatory rule and shall include all of the information listed in subdivision (g)(i) to 

(iii) of this subrule. 

 (5) The method for determining compliance with the emission limits in subrule (4) of this 

rule is as follows: 

 (a) If the emission limit is in the form of pounds of oxides of nitrogen per million 

British thermal unit, then the unit is in compliance if the sum of the mass emissions from 

the unit that occurred during the ozone control period, divided by the sum of the heat input 

from the unit that occurred during the ozone control period, is less than or equal to the 

limit in subrule (4) of this rule. 

 (b) For an emission unit not subject to subdivision (a) of this subrule, the method for 

determining compliance shall be a method acceptable to the department. 

 (6) An owner or operator of a source of oxides of nitrogen that is subject to the provisions 

of this rule may participate in Michigan’s emission trading program, being R 336. 2201 to 

R 336.2218. 

 (7) The owner or operator of an emission unit subject to subrule (2) of this rule shall 

measure oxides of nitrogen emissions with a continuous emission monitoring system; an 

alternate method as described in 40 C.F.R. part 60 or 75 and acceptable to the department; or 

a method currently in use and acceptable to the department, including methods contained in 

existing permit conditions. The provisions of 40 C.F.R. parts 60 and 75 (2001) are adopted 

by reference in these rules. Copies of the regulations may be inspected at the Lansing office 
R 336.1801 8-6 As Amended December 4, 2002 

of the air quality division of the department of environmental quality. Copies of the 

regulations may be obtained from the Department of Environmental Quality, Air Quality 

Division, 525 West Allegan Street, P.O. Box 30260, Lansing, Michigan 48909-7760, or from 

the Superintendent of Documents, Government Printing Office, P.O. Box 371954, 

Pittsburgh, Pennsylvania 15250-7954, at a cost at the time of adoption of these rules of 

$53.00 for part 60 and $55.00 for part 75; or on the United States government printing office 

internet web site at www.access.gpo.gov. 

 (8) The owner or operator of a boiler, process heater, stationary internal combustion 

engine, stationary gas turbine, cement kiln, or any other stationary emission unit that is 

subject to the provisions of subrule (4) of this rule shall measure oxides of nitrogen 

emissions by any of the following: 

 (a) Performance tests described in subrule (9) of this rule. 

 (b) Through the use of a continuous emission monitor in accordance with the 

provisions of subrule (11) of this rule. 

 (c) According to a schedule and using a method acceptable to the department. 

 (9) An owner or operator of an emission unit that measures oxides of nitrogen emissions 

by performance tests as specified in subrule (8) of this rule shall do all of the following: 

 (a) Conduct an initial performance test not later than 90 days after the compliance 

deadline. For an emission unit that is not in service on or after the compliance deadline, 

the owner or operator shall contact the department and schedule an alternate initial 

performance test as agreed to by the department. 

 (b) After the initial performance test, conduct a compliance performance test each 

ozone control period or according to the following schedule: 

 (i) After 2 consecutive ozone control periods in which the emission unit 

demonstrates compliance, an owner or operator shall conduct performance tests at least 

once every 2 years during the ozone control period. 

 (ii) After a total of 4 consecutive ozone control periods in which the emission unit 

has remained in compliance, an owner or operator shall conduct performance tests at 

least once every 5 years during the ozone control period. 

 (c) If an emission unit is not in compliance at the end of an ozone control period, then 

the owner or operator shall conduct a compliance performance test each ozone control 

period, but can again elect to use the alternative schedule specified in subdivision (b) of 

this subrule. 

 (d) An owner or operator shall submit 2 copies of each compliance performance test to 

the department within 60 days of completion of the testing. The test results shall be 

presented and include data as requested in the department format for submittal of source 

emission test plans and reports. All performance test reports shall be kept on file at the 

plant and made available to the department upon request. 

 (10) An owner or operator of an emission unit who is required to conduct performance 

testing under subrule (8) of this rule shall submit a test plan to the department, not less than 

30 days before the scheduled test date. To ensure proper testing, the plan shall supply the 
R 336.1801 8-7 As Amended December 4, 2002 

information in the department format for submittal of source emission test plans and reports. 

The owner or operator shall give the department a reasonable opportunity to witness the 

tests. 

 (11) An owner or operator of an emission unit that measures oxides of nitrogen emissions 

by a continuous emission monitoring system or an alternate method, as specified in 

subrule (7) or (8) of this rule, shall do either of the following: 

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

comply with the quality assurance procedures in appendix F, or 40 C.F.R., part 75, and 

associated appendices, as applicable and acceptable to the department. Title 40 C.F.R., 

parts 60 and 75, are adopted by reference in subrule (7) of this rule. 

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

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

a continuous emission monitoring system for oxides of nitrogen pursuant to other 

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

calibration, and reporting requirements specified by federal, state, or local rules. 

 (12) The owner or operator of an emission unit that is subject to this rule shall submit a 

summary report, in an acceptable format, to the department within 60 days after the end of 

each ozone control period. The report shall include all of the following information: 

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

specified emission unit or utility system. 

 (b) If emissions or emission rates exceed the emissions or rates allowed for in the 

ozone control period by the applicable emission limit, the cause, if known, and any 

corrective action taken. 

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

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

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

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

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

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

 (13) Table 81 reads as follows: 
R 336.1801 8-8 As Amended December 4, 2002 

Table 81 

Boilers and process heaters with 

heat input capacity of 250 million Btu or more 

oxides of nitrogen (NOx) emission limitations 

(pounds NOx per million Btu of heat input 

averaged over the ozone control period) 

Fuel type Emission limit 

Natural gas 0.20 

Distillate oil 0.30 

Residual oil 0.40 

Coal 

 (1) Coal spreader stoker 

 (2) Pulverized coal fired 

0.40 

0.40 

Gas (other than natural gas)1 0.25 

For units operating with a combination of gas, oil, or coal, a variable emission limit 

calculated as the heat input weighted average of the applicable emission limits shall be 

used. The emission limit shall be determined as follows: 

Emission limit = a(0.20) + b(applicable oil limit) + c(applicable coal limit) + d(0.25) 

 Where: 

 a = Is the percentage of total heat input from natural gas 

 b = Is the percentage of total heat input from oil 

 c = Is the percentage of total heat input from coal 

 d = Is the percentage of total heat input from gas (other than natural gas) 

1

This may include a mixture of gases. In this case, natural gas may be part of the mixture. 
R 336.1801 8-9 As Amended December 4, 2002 

 (14) The provisions of this rule do not apply to the following emission unit or units: 

 (a) A unit that is subject to oxides of nitrogen standards, which have been promulgated 

in a federal implementation plan under section 110(c) of the clean air act, required under 

section 126 of the clean air act, or promulgated in a federal regulation under 40 C.F.R. part 

51 or part 60 and which are equally stringent or more stringent than this rule. 

 (b) A unit that is subject to any other rule included in this part. 

 (c) A peaking unit. The owner or operator shall retain records of capacity for a period 

of 5 years demonstrating that the unit meets the definition of a peaking unit. The unit shall 

become subject to the provisions of this rule on January 1 of the year following failure to 

meet the peaking unit definition. 

History: 2000 MR 7, Eff. May 17, 2000; .2002 MR 22, Eff. December 4, 2002. 
ATTACHMENT Q 

Applicable Canadian Provincial Air Regulations 
This is not the official version.

Copyright © 2000: Queen’s Printer, St. John's, Newfoundland, Canada Important Information

(Includes disclaimer and copyright information and details about the availability of printed and electronic versions of the Statutes.) 

CONSOLIDATED NEWFOUNDLAND REGULATION 957/96 

Air Pollution Control Regulations

under the 

Environment Act

(O.C. 96-246) 

Under the authority of section 14 of the Environment Act and the Subordinate 

Legislation Revision and Consolidation Act, the Lieutenant-Governor in Council makes the following regulations. 

REGULATIONS 

Stationary source of air contamination 5. (1) Subject to section 4, the standards for concentrations of air contaminants from a stationary source at a point of impingement shall be those as prescribed in Schedule B. (2) The amount of air contaminants in the atmosphere at the point of impingement measured or calculated in accordance with a method approved by the minister shall not exceed the amounts established in Schedule B. (3) For the purpose of enforcing these regulations a contaminant at a point of impingement shall be calculated in accordance with a method approved by the minister. (4) A person shall not operate or cause to be operated a stationary source in a manner that does not comply with the standards prescribed in Schedule B. 

26/81 s7 

Visible emissions 7. A visible emission chart shall be used by the department to determine the opacity of a visible emission. 

26/81 s8 

Visible emission standards 8. (1) A person shall not cause or permit to be caused a visible emission having an opacity greater than density No. 1 on the visible emission chart referred to in section 7. (2) Notwithstanding subsection (1), for a period of not more than 4 minutes in the aggregate in a half hour period, visible emission may have an opacity exceeding density No. 1 but not exceeding density No. 2 on the visible emission chart. (3) Notwithstanding subsection (1), where a new fire is started in combustion process equipment, the visible emission may have an opacity not exceeding density No. 3 on 

the visible emission chart for a period not more thquarter hour period up to one hour after the new f

Recording devices 12. (1) The minister may require the installation onecessary to record the periods of operation of proequipment, the records from which shall be availa(2) The minister may require the installation of sudevices as are necessary to measure and record cotheir source and points of impingement, the recordshall be available to a department official. 

Sch

Standards for Emitted Co

Item Col. 1 Col. 2 

Name of 

Contaminant

Unit of Concentration 

1. Acetic Acid 

2. Acetylene 

3. Acetone 

4. Acrylamide 5. Ammonia 

6. Antimony Total micrograms of 

antimony in free and combined form per cumetre of air.

7. Arsine 

8. Beryllium Total micrograms of 

beryllium in free and 
combined form per cubic 

metre of air.

9. Boron 

Tribromide

80

10. Boron 

Trichloride

80

11. Boron Trifluoride

4

12. Boron Total micrograms of 

boron in free and combined form per cubic metre of air.

80

13. Bromine 6014. Cadmium Total micrograms of 

cadmium in free and combined form per cubic metre of air.

4

15. Calcium 

hydroxide

22

16. Calcium Oxide 16

17. Carbon Black 2118. Carbon 

Disulphide

270

19. Carbon 

Monoxide

5000

20. Chlorine 250

21. Chlorine Dioxide 7022. Copper Total micrograms of 

copper in free and combined form per cubic metre of air.

80

23. Cresols 190

24. Decaborane 25. Diborane 

26. Dicapryl 

Phthalate

27. Dimethyl 

Disulphide

28. Dimethyl 

Sulphide

29. Dioctyl Phthalate 

30. Dustfall Micrograms per squar

metre.

31. Ethyl Acetate 

32. Ethyl Acrylate 

33. Ethyl Benzene 34. Ferric Oxide 35. Fluorides, 

(Gaseous) (April 15 to October 15)

Micrograms of gaseouinorganic fluoride per cubic metre of air expressed as hydrogen fluoride.

36. Fluorides, (Total) 

(April 15 to October 15)

Total micrograms of inorganic fluoride per cubic metre of air expressed as hydrogen fluoride.

37. Fluorides, (Total) 

(October 16 to April 14)

Total micrograms of inorganic fluoride per cubic metre of air expressed as hydrogen fluoride.

38. Formaldehyde 39. Formic Acid 
40. Furfural 800

41. Furfuryl Alcohol 250042. Hydrogen 

Chloride

80

43. Hydrogen 

Cyanide

950

44. Hydrogen 

sulphide

25

45. Iron (metallic) 846. Lead Total micrograms of lead 

in free or combined form per cubic metre of air.

8

47. Lithium Hydrides Total micrograms of 

lithium hydrides per cubic metre of air.

6.2

48. Lithium Total micrograms of 

lithium in other than hydride compounds per cubic metre of air.

50

49. Magnesium 

Oxide

Total micrograms of magnesium oxide per cubic metre of air.

80

50. Mercaptans Total micrograms of 

mercaptans per cubic metre of air expressed as methyl mercaptans.

16

51. Mercury (alkyl) Total micrograms of alkyl 

mercury compounds per cubic metre of air.

1.2

52. Mercury Total micrograms of 

mercury in free and combined form per cubic metre of air.

4

53. Methyl Acylate 3.3

54. Methyl Alcohol 

55. Methyl 

Chloroform (1,1,1-Trichloroethane)

56. Methyl Ethyl 

Ketone (2-Butanone)

57. Methyl 

Methacrylate

58. Milk Powder 

59. Monomethyl 

Amine

60. Nickel Total micrograms of 

nickel in free and combined form per cumetre of air.

61. Nickel Carbonyl 

62. Nitic Acid 

63. Nitrilotriacetic 

Acid

64. Nitrogen Oxides Micrograms of nitroge

oxides per cubic metre air expressed as NO2

65. Ozone 66. Pentaborane 

67. Phenol 68. Phosgene 

69. Phosphoric Acids Micrograms of phosph

acids per cubic metre air expressed as P2O5
70. Phthalic 

Anhydride

80

71. Propylene 

Dichloride

2000

72. Silver Total micrograms of silver 

in free and combined form per cubic metre of air.

2.5

73. Styrene 330

74. Sulphur Dioxide 68075. Sulphuric Acid 80

76. Suspended 

Particulate Matter (particulates less than 44 microns in size)

Total micrograms of suspended particulate matter per cubic metre of air.

80

77. Tellurium 

(except hydrogen telluride)

25

78. Tetrahydrofuran 77000

79. Tin Total micrograms of tin in 

free and combined form per cubic metre of air.

25

80. Titanium Total micrograms of 

titanium in free and combined form per cubic metre of air.

80

81. Toluene 1600

82. Toluene Diisocyanate 0.8

83. Trichloroethylene 70000

84. Vanadium Total micrograms of 

vanadium in free and 

4.1

combined form per cumetre of air.

85. Xylenes 86. Zinc Total micrograms of z

in free and combined fper cubic metre of air.

(1) Unit of concentration is micrograms of the conmetre of air, unless otherwise noted. 

Earl G. Tucker, Queen

(This document contains the reprints of original d

and August 8, 1997, p

©Earl G. Tucker, Quee
Environmental Protection Act 

Loi sur la protection de l'environnement

R.R.O. 1990, REGULATION 346

Amended to O. Reg. 342/01

GENERAL - AIR POLLUTION 

Notice of Currency:* This document is up to date.*This notice is usually current to within two business days of accessing this document. For more current amendment information, see the Table of Regulations 

(Legislative History).

This Regulation is made in English only.

Control of Air Contaminants

5. (1) The maximum concentration of a contaminant set out in Column 1 of Schedule 1 at a point of impingement from a source of contaminant, other than a motor vehicle, shall not be greater than the concentration set out opposite thereto in Column 3 of Schedule 1, expressed in the unit of concentration set out opposite thereto in Column 2 of Schedule 1. R.R.O. 1990, Reg. 346, s. 5 (1).(2) The concentration of a contaminant at a point of impingement may be calculated in accordance with the Appendix. R.R.O. 1990, Reg. 346, s. 5 (2).(3) No person shall cause or permit the concentration of a contaminant at a point of impingement to exceed the standard prescribed in Schedule 1. R.R.O. 1990, Reg. 346, s. 5 (3).6. No person shall cause or permit to be caused the emission of any air contaminant 

to such extent or degree as may,

(a) cause discomfort to persons;(b) cause loss of enjoyment of normal use of property;(c) interfere with normal conduct of business; or(d) cause damage to property. R.R.O. 1990, Reg. 346, s. 6.

7. (1) The Ministry shall prepare a chart to be known as the "Visible Emission 

Chart of the Province of Ontario". R.R.O. 1990, Reg. 346, s. 7 (1).(2) The Visible Emission Chart of the Province of Ontario shall consist of two oneinch squares on a white background such that,

(a) the area within the square designated as number 1 shall have black dots or lines evenly spaced such that approximately 20 per cent of the area is black;(b) the area within the square designated as number 2 shall have black dots or lines evenly spaced such that approximately 40 per cent of the area is black. R.R.O. 1990, Reg. 346, s. 7 (2).

(3) For the purpose of enforcing the Act and this Regulation no person other than a provincial officer who has been trained by the Ministry in the identification of opacity shall determine the opacity of a visible emission. R.R.O. 1990, Reg. 346, s. 7 (3).8. (1) Subject to subsection (2), no person shall cause or permit to be caused a visible emission,

(a) having shades of grey darker than numbof the Province of Ontario at the point of em(b) that obstructs the passage of light to a depoint of emission. R.R.O. 1990, Reg. 346, s

(2) A visible emission from a source of combperiod of not more than four minutes in the aggmay,

(a) be in shades of grey darker than number the Visible Emission Chart of the Province or(b) obstruct the passage of light to a degrgreater than 40 per cent at the point of s. 8 (2).

9. Where at any stationary source of air pollutiomanner or a change in operating conditions occupart thereof is made for some purpose, resulting that may result in quantities or concentrations in 5, 6 and 8,

(a) the owner or operator of the source of air 

(i) immediately notify a provincial offparticulars of such failure, change or shu(ii) furnish the provincial officer with this practicable, of such failure, change or 

(b) if the provincial officer considers it advwriting, the continuance of such operation fconsiders reasonable in the circumstances aoperator such terms and conditions for such considers necessary in the circumstances. R

10. (1) No person shall burn or permit to be buror incinerator any fuel or waste except the fuel or 

equipment or incinerator was designed. R.R.O. 19(2) No person shall burn or permit to be burned incinerator any fuel or waste at a greater rate thaor incinerator was designed. R.R.O. 1990, Reg. 34

11. Except for heat, sound, vibration or radiation

(a) construct, alter, demolish, drill, blast, crpermit the construction, alteration, demoliscreening of anything so that a contaminanproperty on which the construction, alteracrushing or screening is being carried out; o(b) sandblast or permit the sandblasting of emitted into the air,

to an extent or degree greater than that which wocontrol the emission of the contaminant were ims. 11.12. (1) In this section,
"apartment incinerator" means an incinerator that is located in or on the site of a 

building containing more than one dwelling unit and used to burn domestic waste from more than one dwelling unit. R.R.O. 1990, Reg. 346, s. 12 (1).

(2) No person shall operate or permit the operation of,

(a) an apartment incinerator, domestic incinerator, multiple chamber incinerator or starved air incinerator burning domestic waste;(b) a multiple chamber incinerator or starved air incinerator burning solid industrial waste;(c) an incinerator burning liquid industrial waste, industrial slurries or sludges, sewage sludges or slurries, gaseous waste, organic vapour or fume; or(d) a municipal incinerator burning solid waste or sludges,

that causes or is likely to cause a concentration in the combustion gases emitted into the natural environment, of organic matter having a carbon content, expressed as equivalent methane, being an average of ten measurements taken at approximately one minute intervals, greater than 100 parts per million by volume, measured on an undiluted basis. R.R.O. 1990, Reg. 346, s. 12 (2).(3) Subsection (2) does not apply to prohibit the operation of a catalytic incinerator. R.R.O. 1990, Reg. 346, s. 12 (3).(4) No person shall operate or permit the operation of an apartment incinerator without a certificate of approval issued under section 9 of the Act. R.R.O. 1990, Reg. 346, s. 12 (4).13. No person shall store, handle or transport any solid liquid or gaseous material or substance in such manner that an air contaminant is released to the atmosphere. R.R.O. 1990, Reg. 346, s. 13.

Schedule 1

Column 1 Column 2 Column 3

Item

Name of Contaminant Unit of Concentration

Concentration at Pointof Impingement - HalfHour Average

1. Acetic Acid Micrograms of acetic acid per 

cubic metre of air

2,500

2. Acetylene Micrograms of acetylene per 

cubic metre of air

56,000

3. Acetone Micrograms of acetone per 

cubic metre of air

48,000

4. Acrylamide Micrograms of acrylamide per 

cubic metre of air

45

4.1 Acrylonitrile Micrograms of acrylonitrile per 

cubic metre of air

180

5. Ammonia Micrograms of ammonia per 3,600

cubic metre of air

6. Antimony Total microgram

in free and combcubic metre of air

7. Arsine Micrograms of a

metre of air

8. Beryllium Total microgram

in free and combcubic metre of air

9. Boron Tribromide Micrograms 

tribromide per cair

10. Boron Trichloride Micrograms of bo

per cubic metre o

11. Boron Trifluoride Micrograms of bo

per cubic metre o

12. Boron Total microgram

free and combicubic metre of air

13. Bromine Micrograms of 

cubic metre of air

14. Cadmium Total microgram

in free and combcubic metre of air

15. Calcium hydroxide Micrograms 

hydroxide per cub

16. Calcium Oxide Micrograms of 

per cubic metre o

17. Carbon Black Micrograms of ca

cubic metre of air

18. Carbon Disulphide Micrograms 

disulphide per cair

19. Carbon Monoxide Micrograms 

monoxide per cub

20. Chlorine Micrograms of 

cubic metre of air

21. Chlorine Dioxide Micrograms of ch

per cubic metre o
21.1 Chloroform Micrograms of chloroform per 

cubic metre of air

300

22. Copper Total micrograms of copper in 

free and combined form per cubic metre of air

100

23. Cresols Micrograms of cresols per cubic 

metre of air

230

24. Decaborane Micrograms of decaborane per 

cubic metre of air

50

25. Diborane Micrograms of diborane per 

cubic metre of air

20

26. Dicapryl Phthalate Micrograms of dicapryl 

phthalate per cubic metre of air

100

27. Dimethyl Disulphide Micrograms of dimethyl 

disulphide per cubic metre of air

40

28. Dimethyl Sulphide Micrograms of dimethyl 

sulphide per cubic metre of air

30

29. Dioctyl Phthalate Micrograms of dioctyl phthalate 

per cubic metre of air

100

30. Dustfall Micrograms per square metre 8,00031. Ethyl Acetate Micrograms of ethyl acetate per 

cubic metre of air

19,000

32. Ethyl Acrylate Micrograms of ethyl acrylate 

per cubic metre of air

4.5

33. Ethyl Benzene Micrograms of ethyl benzene 

per cubic metre of air

3,000

33.1 Ethyl Ether Micrograms of ethyl ether per 

cubic metre of air

7,000

34. Ferric Oxide Micrograms of ferric oxide per 

cubic metre of air

75

35. Fluorides, (Gaseous)

(April 15 to October 15)

Micrograms of gaseous, inorganic fluoride per cubic metre of air expressed as hydrogen fluoride

4.3

36. Fluorides, (Total)

(April 15 to October 15)

Total micrograms of inorganic fluoride per cubic metre of air expressed as hydrogen fluoride

8.6

37. Fluorides, (Total) Total micrograms of inorganic 

(October 16 to April 14) fluoride per cubi

expressed as hydr

38. Formaldehyde Micrograms of 

per cubic metre o

39. Formic Acid Micrograms of f

cubic metre of air

40. Furfural Micrograms of 

cubic metre of air

41. Furfuryl Alcohol Micrograms of f

per cubic metre o

41.1

n-Heptane Micrograms of 

cubic metre of air

42. Hydrogen Chloride Micrograms o

chloride per cubic 

43. Hydrogen Cyanide Micrograms o

cyanide per cubic 

44. Hydrogen Sulphide Micrograms o

sulphide per cubi

45. Iron (metallic) Micrograms of m

cubic metre of air

45.1 Isopropyl Benzene Micrograms o

benzene per cubic 

46. Lead Total micrograms 

and combined fmetre of air

47. Lithium Hydrides Total microgram

hydrides per cubi

48. Lithium Total microgram

other than hydriper cubic metre o

49. Magnesium Oxide Total micro

magnesium oxidmetre of air

50. Mercaptans Total micro

mercaptans per cair expressed mercaptans

51. Mercury (alkyl) Total microgram

mercury compoumetre of air
52. Mercury Total micrograms of mercury in 

free and combined form per cubic metre of air

5.0

53. Methyl Acrylate Micrograms of methyl acrylate 

per cubic metre of air

4.0

54. Methyl Alcohol 

(Methanol)

Micrograms of methyl alcohol per cubic metre of air

12,000

55. Methyl Chloroform

(1-1-1 Trichloroethane)

Micrograms of methyl chloroform per cubic metre of air

350,000

56. Methyl Ethyl Ketone 

(2-Butanone)

Micrograms of methyl ethyl ketone per cubic metre of air

30,000

56.1 Methyl Isobutyl Ketone Micrograms of methyl isobutyl 

ketone per cubic metre of air

1,200

57. Methyl Methacrylate Micrograms of methyl 

methacrylate per cubic metre of air

860

58. Milk Powder Micrograms of milk powder per 

cubic metre of air

20

58.1 Mineral Spirits Micrograms of mineral spirits 

per cubic metre of air

7,800

59. Monomethyl Amine Micrograms of monomethyl 

amine per cubic metre of air

25

60. Nickel Total micrograms of nickel in 

free and combined form per cubic metre of air

5

61. Nickel Carbonyl Micrograms of nickel carbonyl 

per cubic metre of air

1.5

62. Nitric Acid Micrograms of nitric acid per 

cubic metre of air

100

63. Nitrilotriacetic Acid Micrograms of nitrilotriacetic 

acid per cubic metre of air

100

64. Nitrogen Oxides Micrograms of nitrogen oxides 

per cubic metre of air expressed 

as NO2

500

65. Ozone Micrograms of ozone per cubic 

metre of air

200

66. Pentaborane Micrograms of pentaborane per 

cubic metre of air

3.0

67. Phenol Micrograms of ph

metre of air

68. Phosgene Micrograms of 

cubic metre of air

69. Phosphoric Acids Micrograms of ph

per cubic metre o

as P2O5

70. Phthalic Anhydride Micrograms 

anhydride per cub

71. Propylene Dichloride Micrograms o

dichloride per cub

71.1 Propylene Oxide Micrograms of p

per cubic metre o

72. Silver Total microgram

free and combicubic metre of air

73. Styrene Micrograms of 

cubic metre of air

74. Sulphur Dioxide Micrograms of s

per cubic metre o

75. Sulphuric Acid Micrograms of 

per cubic metre o

76. Suspended Particulate 

Matter(particulate less than 44 microns in size)

Total microgram

particulate matt

metre of air

77. Tellurium (except 

hydrogen telluride)

Micrograms of teand combined fmetre of air

78. Tetrahydrofuran Micrograms of t

per cubic metre o

79. Tin Total microgram

and combined fmetre of air

80. Titanium Total micrograms 

free and combicubic metre of air

81. Toluene Micrograms of 

cubic metre of air

82. Toluene Di-isocyanate Micrograms of 
isocyanate per cubic metre of 

air

83. Trichloroethylene Micrograms of 

trichloroethylene per cubic metre of air

3,500

84. Trifluorotrichloro 

Ethane

Micrograms of trifluoro trichloroethane per cubic metre of air

2.4 million

85. Vanadium Total micrograms of vanadium 

in free and combined form per cubic metre of air

5.0

85.1 Vinylidene Chloride Micrograms of vinylidene 

chloride per cubic metre of air

30

86. Xylenes Micrograms of xylenes per 

cubic metre of air

2,300

87. Zinc Total micrograms of zinc in free 

and combined form per cubic metre of air

100

R.R.O. 1990, Reg. 346, Sched.; O. Reg. 795/94, s. 1; O. Reg. 342/01, s. 1.

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Updated to 26 November 2002

c. Q-2, r. 20 Regulation respecting the quality of the atmosphereEnvironment Quality Act(R.S.Q., c. Q-2, ss. 20, 31, 53, 70, 71, 72, 87 and 124.1) DIVISION IVOPACITY OF EMISSIONS 10. Opacity standards: Subject to the cases provided for in sections 35, 36, 41 and 

84, the concentration of contaminants discharged into the atmosphere by a stationary source must not exceed 20 % of opacity according to one or the other of 

the measuring methods provided for in paragraphs 

a or 

b of section 96. 

R.R.Q., 1981, c. Q-2, r. 20, s. 10. 11. Exceptions: Section 10 does not apply to the starting of a fire or the soot 

blowing. The degree of opacity may then, for a maximum period of 4 consecutive minutes exceed 20 % but never be equal to or higher than 60 % of opacity.  During the operation of a stationary source, the degree of opacity of an emission may also exceed 20 % for one or several periods not exceeding 4 minutes in any one hour, but never be equal to or higher than 40 %. R.R.Q., 1981, c. Q-2, r. 20, s. 11. DIVISION VEMISSION OF ORGANIC COMPOUNDS 12. General standards: Subject to cases provided for in sections 13 and 14, a stationary source other than those mentioned in section 15 may not emit into the atmosphere: 

(a) more than 6,8 kilograms per day and 1,3 kilograms per hour of organic 

compounds in the case where organic solvents or substances which contain them are submitted to a baking process or come in contact with a flame; 

(b) more than 15 kilograms per day and 3 kilograms per hour of organic 

compounds for photochemically reactive organic compounds which are not submitted to a baking process or do not come in contact with a flame; 

(c) more than 1 400 kilograms per day or 200 kilograms per hour of organic 

compounds where non-photochemically reactive solvents are not submitted to a baking process or do not come in contact with a flame. 

 For the purposes of enforcing this section, the diprocess constitute only one stationary source. Orgmentioned in subparagraphs 

b and c of the first pa

produced during the 12 hours used for drying, follorganic solvents or substances which contain themR.R.Q., 1981, c. Q-2, r. 20, s. 12. 13. Excessive emissions: Organic compound em

prescribed in section 12 provided that there is a reatmosphere of at least 90 % for incineration of orgin other cases. R.R.Q., 1981, c. Q-2, r. 20, s. 13. 14. Restrictions: Sections 12 and 13 do not apply 

(a) establishments where organic solvents are (b) the transport and storage of organic solven

them; 

(c) the use of insecticides, pesticides or herbic(d) to the use or evaporation of halogen hydro

R.R.Q., 1981, c. Q-2, r. 20, s. 14. 15. Shops, or coating or impregnation rooms f

A shop or coating or impregnation room for organphotochemically reactive organic compounds the atmosphere exceeds 15 kilograms per day, cannot into the atmosphere beyond the standards of the foTABLE [Q-2r20#03, see R.R.Q., 1981, 8-7category type of coating emission standard (in kg of organic compound per litre of produit used)  can factory primer and metal  lacquer 0,34  can interior and top  coating 0,51  weld coating 0,66  sealing compound 0,4 electric cable plant coating  textile plant fabric coating pr vinyl coating 0,45 
 coated paper plant impregnation 0,35 

 motor vehicle  assembly plant primer coating 0,23  finish coating 0,34  touch-up, final repair 0,58  motor vehicle repair shop  and any other shop or  coating or impregnation room  all operations 0,58 [Q-2r20#03, FIN]  In addition to the standards prescribed in the first paragraph, a new or existing paint room must: 

(a) be equipped with a particulate matter collection system designed to collect 

more than 90 % of the particulate matters discharged in the atmosphere; 

(b) be equipped with a gas exhaust stack at least 5 metres taller than the 

building in which painting operations take place; and 

(c) exhaust the gases into the atmosphere with an updraft speed of at least 15 

metres per second.  The emission standards for organic compounds provided for in this Division apply from 1 June 1981 to existing stationary sources. R.R.Q., 1981, c. Q-2, r. 20, s. 15; O.C. 187-88, s. 1. This section applies in particular to immoveables comprised in a reserved area and in agricultural zone established under the Act preserve agricultural land (R.S.Q., c. P-41.1).15.1. Paint shops in a light motor vehicle assembly plant: No person who sets up or modifies a paint shop or room which is part of a light motor vehicle assembly plant may allow the emission into the atmosphere of 

organic compounds in excess of the standards prescribed in the following table: [Q-2r20#23, see 1988 G.O. 2, 1268]  Emission standards in kg of organic compounds per  litre of solids applied Operation Existing plant  New plant Standard up 

to 30 Sept. 1989 Standard from 1 Oct. 1989 to 31 Dec. 1992 Standard from 1 January 1993  Prime  coat 0,16 0,43 0,43 0,. Guide  coat 1,40 5,57 1,40 1,4 Top  coating 1,89 11,92 3,7[Q-2r20#23, FIN]  The operator of a motor vehicle assembly plant m

Ministère de l'Environnement et de la Faune the maverage monthly quantity of volatile organic compsolids applied to bodies, and also the volume of pin such paint, the quantity of diluting solvents addratio, and any other information necessary for the computation shall be done with the method establStates, reference 40CFR 60.393.  The standards prescribed in the second paragraph 

shop or room governed by this section. O.C. 187-88, s. 2; S.Q., 1994, c. 17, s. 77. This section applies in particular to immoveables in agricultural zone established under the Act to pc. P-41.1).DIVISION VIIFUGITIVE EMISSIONS 17.

Dust emissions: Any person who wrecks, bu

building or a thoroughfare must spread water or aprevent the raising of dust in all cases where the cabout the emission of dust which produces any efparagraph in fine of section 20 of the Act. 

R.R.Q., 1981, c. Q-2, r. 20, s. 17. 18. Access lanes, storage and transport: When 

and road ways located on the same property as a saggregates, materials, mine refuse, ore, ore concenenumerated in the second paragraph in fine of secresponsible for the contamination source must tak
control these emissions so as to eliminate those effects. 

 This section applies, mutatis mutandis, to the transport by conveyor belt, truck or 

railway car of the materials mentioned in the first paragraph. R.R.Q., 1981, c. Q-2, r. 20, s. 18. 19. Transfer and free fall: In the case where the transfer or free fall of materials of 

any kind including aggregates, mine rejects ore, ore concentrate or pellets, brings about the emission of dust which can be seen in the atmosphere more than 2 metres away from the emission source, the person responsible for that source of atmospheric contamination must take the necessary measures so that: 

(a) the stationary transfer point is included in an enclosed space equipped with 

ducts which draw dust to a dust collector so that the emissions of particulate matters into the atmosphere are in compliance with the concentration standard established in section 25; or 

(b) the free fall height of these materials does not exceed 2 metres. 

R.R.Q., 1981, c. Q-2, r. 20, s. 19. 20. Sandblasting: Dust emissions resulting from dry sandblasting operations must 

be controlled by using an enclosure or screen in order to confine the dust inside the spaces thus enclosed or closed, except in the case of a metal bridge.  This section applies, mutatis mutandis, to wet-type sandblasting operations when 

there are dust emissions that can be seen in the atmosphere more than 2 metres from the emission source. R.R.Q., 1981, c. Q-2, r. 20, s. 20. 21. Recuperated dust: Dust recuperated by a dry collector must be handled and 

transported so that there is no dust released into the atmosphere which can be seen 2 metres from the emission source. When it is not recycled, it must be stored, spread or disposed of on the ground and the necessary measures must be taken to prevent 

any release of dust into the atmosphere which can be seen 2 metres away from the emission source, and in order to prevent water contamination. R.R.Q., 1981, c. Q-2, r. 20, s. 21. 22. Waste: It is forbidden to burn residual materials in the open air, even to 

recuperate it in part or in whole, except for limbs, trees, dead leaves, explosives and empty containers of explosives.  The presence in the environment of smoke originating from combustion prohibited by the first paragraph is prohibited within the meaning of the second paragraph of section 20 of the Act.  This section does not apply to solid waste disposal sites situated north of the 55th

parallel, nor to those mentioned in Division X or in section 125 of the Regulation respecting solid waste (c. Q-2, r. 14). The person responsible for such a solid waste disposal site must however take the necessary measure to prevent smoke emissions 

from producing one effect or the other enumerated section 20 of the Act. R.R.Q., 1981, c. Q-2, r. 20, s. 22; O.C. 492-2000, 23. Disposal of fuels: It is forbidden to burn foss

the open air unless one has been issued a certifica

under section 22 of the Act.  This section does not apply to industrial flares, n

given to firemen. R.R.Q., 1981, c. Q-2, r. 20, s. 23; S.Q., 1988, c. 4DIVISION VIIIPARTICULATE MATTER GENERAL EMISSIO24. Quantities allowed: Except for the special cato XV, XVII to XXII, XXIV, XXVI to XXVIII anparticulate matters into the atmosphere in excess orespectively for existing and new stationary sourc Moreover, a new grain processing plant whose nthan 15 tonnes per hour for a reduction of 15 poin

placed at least 300 metres from a dwelling area esfrom a dwelling situated in the direction of the premetres from any other dwelling, except for the onowner or operator of the grain processing plant. Fthis paragraph, a prevailing wind is a wind whichinclusively blows in average of 20 % of the time icompass dial with 8 directions is used and more thwhere a compass dial with 16 directions is used, astation nearest to the plant. R.R.Q., 1981, c. Q-2, r. 20, s. 24. 25. Concentration: No mill, distillery, brewery, 

mixing plant, concrete plant, vitreous enamel, earplant, polyvinyl chloride production or processing must emit particulate matter into the atmosphere wmilligrams per cubic metre, under standard condit This standard applies also to emissions coming f

except wood, any storage in confined environmensinking of a supply water well, any welding operasandblasting and to any process for the preparatiodrying of ore or ore concentrate, as well as to the in a plant for the preparation, concentration, aggloores, except for the process of aluminium hydrate 
R.R.Q., 1981, c. Q-2, r. 20, s. 25. 

26. Date of enforcement: This Division applies from 1 December 1981 to existing stationary sources except to existing mills which will be subject to it from 1 December 1983. R.R.Q., 1981, c. Q-2, r. 20, s. 26. DIVISION IXUSE OF FOSSIL FUELS 

27. Particulate matter emissions: A fossil fuel burning equipment cannot emit particulate matters into the atmosphere beyond the standards prescribed in the 

following table: TABLE [Q-2r20#04, see R.R.Q., 1981, 8-718]  emission standards (particulate matters mg per MJ) heat input capacity in fuel as fired type of fuel new installation existing installation*  between 3 and 15 MW gas or oil product 60 85  between 3 and 70 MW coal 60 85  Š 15 MW gas or oil product 45 60  Š 70 MW coal 45 60  * the standards prescribed in this section apply from 1 June, 1981 to existing fuel burning equipments. [Q-2r20#04, FIN]  In the case of an existing fuel burning equipment with a capacity greater than 125 

megawatts, used in an electric power plant, the emission standard is 45 milligrams per megajoule and applies from 1 December 1980. R.R.Q., 1981, c. Q-2, r. 20, s. 27. 28. Nitrogen oxide emissions: A new fuel burning equipment fuel is used must not emit nitrogen oxides into the atmosphere beyond the standards prescribed in the following table: TABLE [Q-2r20#05, see R.R.Q., 1981, 8-719] 

heat input capacity as fired type of fuel emission standards (ppm, dry basis to 3% 02) Š 70 MW coal 500  oil 250  gas 200 between 15 and  70 MW coal 450  oil 325  gas 150 [Q-2r20#05, FIN] R.R.Q., 1981, c. Q-2, r. 20, s. 28. 29. Sulfur content: No person may burn a fuel w

(a) 2,0 % in weight for heavy oil; (b) 1,0 % in weight for intermediate oil; (c) 0,5 % in weight for light oil; and (d) 2,0 % in weight for coal. 

 Notwithstanding subparagraph 

a of the first para

establishment who, on 1 June 1990, has in his posheavy oil with a sulfur content of between 2,0 % acombustion purposes before 31 December 1990 p

(a) he send notice thereof to the Minister befo

quantity, sulfur content and date of purchase and opossession with a sulfur content of between 2,0 % 

(b) he use, before 31 December 1990, a quant

content of less than 2,0 % so that the total sulfur d

establishment for the last 7 months of 1990 is equemissions that would have resulted from the combof heavy oil with a sulfur content of 2,0 %.  A person availing himself of the provisions of th30 January 1991, send the Minister a report indica

last 7 months of 1990, the sulfur content and the qR.R.Q., 1981, c. Q-2, r. 20, s. 29; O.C. 715-90, s. 30. Exception: Standards prescribed in section 2apply in cases where: 
(a) a portion of the sulfur contained in the flue gases is recovered and combined 

to a raw material coming in contact with these gases; 

(b) a portion of the sulfur contained in the flue gases is retained by a gas 

cleaning equipment; or 

(c) another fossil fuel with a low sulfur content is used simultaneously in an oil 

refinery. 

 The person in charge of an establishment to which one of the exceptions prescribed in the first paragraph applies must keep a record book in which he enters the origin, quantity and sulfur content of the heavy oil and coal used; in the case provided for in subparagraph c of the first paragraph, he must also enter in this record book, at least twice a week, the nature, quantity, sulfur content and heating value of each fossil fuel used.  He must forward this record book to the Minister at the end of each calendar year. R.R.Q., 1981, c. Q-2, r. 20, s. 30; O.C. 24

0-85, s. 4; S.Q., 1988, c. 49, s. 54; O.C. 

715-90, s. 2. 31. Sulfur dioxide emissions: Notwithstanding section 30, the quantity of sulfur 

dioxide emitted into the atmosphere by burning any fossil fuel must not exceed that 

emitted by burning a quantity equivalent in heating value of heavy oil whose sulfur content does not exceed the standards prescribed in section 29. R.R.Q., 1981, c. Q-2, r. 20, s. 31; O.C. 240-85, s. 5. 31.1. Notwithstanding section 29, the person in charge of fuel burning equipment 

installed after 1 June 1990 may not use, as fuel, heavy oil or coal with a sulfur content of more than 1,5 % in weight. O.C. 715-90, s. 3. 32. Exhaust gas venting: The exhaust speed of flue gases into the atmosphere 

from a new fuel burning equipment fired with heavy oil or coal must be at least 15 

metres per second at the outlet of a new stack when the equipment operates at nominal capacity. R.R.Q., 1981, c. Q-2, r. 20, s. 32. 33. Stack: The minimum height of any new stack of a fuel burning equipment 

using heavy oil or coal must be equal at least to the one computed in conformity with the method entitled Méthode de calcul de la hauteur minimale des cheminéespublished in 1979 by the Services de protection de l'environnement.  The height of an existing stack cannot be reduced unless it still is, after reduction, in conformity with the height computed according to the method provided for in the 

first paragraph. R.R.Q., 1981, c. Q-2, r. 20, s. 33. 

34. Prohibited emissions: Notwithstanding secti

equipped with fuel burning equipment cannot emiatmosphere in such manner as to exceed quality stdioxide in section 6. R.R.Q., 1981, c. Q-2, r. 20, s. 34. 35. Gas turbines: A gas turbine cannot emit into 

(a) a concentration of contaminants exceedin

or the other of the methods of measure provided f

96, in the case of a simple gas turbine; 

(b) more than 0,2 grams of particulate matters 

new combined gas turbine; 

(c) more than 1,3 grams of nitrogen oxides by 

R.R.Q., 1981, c. Q-2, r. 20, s. 35. 36. Stationary internal combustion engines: A engine cannot emit into the atmosphere: 

(a) a concentration of contaminants exceedin

or another method of measurement provided for in in the case of a new engine; 

(b) more than 4,5 grams of nitrogen oxides by 

engine with a capacity equal to or greater than 1 m

nitrogen oxides per megajoule in the case of a sm

(c) more than 1,8 grams of carbon monoxide 

engine with a capacity equal to or higher than 1 m

monoxide in the case of a smaller engine; 

(d) more than 2,2 grams of hydrocarbons per 

with a capacity equal to or greater than 1 megawaand 0,28 grams of hydrocarbons per megajoule in capacity equal to or greater than 1 megawatt wherand in the case of an engine with a capacity smallR.R.Q., 1981, c. Q-2, r. 20, s. 36. DIVISION XXVIIRON ORE PELLETIZING PLANTS 

86. Indurating process: The indurating process must not emit into the atmosphere particulate matthe following table: TABLE [Q-2r20#17, see R.R.Q., 1981, 8-7
 type of plant standard 

new plant of any capacity 0 ,10 kg/tonne of  pellets produced* existing plant with a nominal 0,36 kg/tonne of yearly production lower than pellets produced* 1 500 000 tonnes of iron oxide pellets existing plant with a nominal 0,12 kg/tonne of yearly capacity equal to or pellets produced* greater than 1 500 000 tonnes of iron oxide pellets [Q-2r20#17, FIN]  * Including the recirculating load, if applicable. R.R.Q., 1981, c. Q-2, r. 20, s. 86. 87. Date of enforcement: This Division applies from 1 December 1981 to existing iron ore pelletizing plant. R.R.Q., 1981, c. Q-2, r. 20, s. 87. SCHEDULE A(s. 24) [Q-2r20#19, see R.R.Q., 1981, 8-730] process weight emission standards rate (tonnes/h) kg/h  0,50 1,3  1,00 2,0  1,50 2,6  2,00 3,2  2,50 3,7  3,00 4,2  3,50 4,6  4,00 5,1  4,50 5,5  5,00 5,9  6,00 6,6  7,00 7,4  8,00 8,1  9,00 8,7  10,0 9,4  12,0 10,6  15,0 12,3 

 17,0 13,3  20,0 14,9  22,0 15,8  25,0 17,2  27,0 17,5  30,0 18,0  35,0 18,6  40,0 19,1  45,0 19,6  50,0 20,0  60,0 20,8  70,0 21,5  80,0 22,1  90,0 22,6  100 23,0  150 25,0  200 26,4  250 27,5  300 28,4  350 29,2  400 29,9  450 30,6  500 31,1  550 31,6  600 32,1 [Q-2r20#19, FIN]  N.B. The process weight rate is determined by thintroduced into any process for a specified period 

Schedule, solid fuels are considered part of the prand combustion air are not.  Interpolation of the data in this Schedule for probe accomplished by use of the equation E = 2,0p0

extrapolation of the data for process weight rates ebe accomplished by use of the equation E = 25,0pstandard in kg/h and P is the process weight rate i In the case of discontinuous operation of the pro

dividing the total process weight rate by the numboperations, less the time during which the equipmprocess weight rate per hour is then calculated by for a typical period of time by the number of hourR.R.Q., 1981, c. Q-2, r. 20, Sch. A. SCHEDULE B(s. 24) 
[Q-2r20#20, see R.R.Q., 1981, 8-730] 

pro cess weight emission standards rate (tonnes/h) (kg/h)  0,50 1,1  1,00 1,7  1,50 2,2  2,00 2,6  2,50 3,0  3,00 3,4  3,50 3,7  4,00 4,0  4,50 4,3  5,00 4,6  6,00 5,2  7,00 5,7  8,00 6,2  9,00 6,6  10,0 7,1  12,0 7,9  15,0 9,1  17,0 9,8  20,0 10,9  22,0 11,6  25,0 13,4  27,0 13,6  30,0 13,8  35,0 14,1  40,0 14,4  45,0 14,7  50,0 15,0  60,0 15,4  70,0 15,8  80,0 16,1  90,0 16,4  100 16,7  150 17,8  200 18,7  250 19,4  300 19,9  350 20,4  400 20,9  450 21,3  500 21,6  550 22,0  600 22,3 

[Q-2r20#20, FIN]  N.B. The process weight rate is determined by thintroduced into any process during a specified per

this Schedule, solid fuels are considered part of thfuels and combustion air are not.  Interpolation of the data in this Schedule for probe accomplished by use of the equation E = 1,7p 0

extrapolation of the data for process weight rate ebe accomplished by use of the equation E = 8p0.16 

process weight rate in t/h.  In the case of discontinuous operation of the procalculated by dividing the total process weight rat

complete operations, less the time during which thThe process weight rate per hour is then calculaterate for a typical period of time by the number of R.R.Q., 1981, c. Q-2, r. 20, Sch. B. SCHEDULE C(s. 96) SCALE FOR THE MEASUREMENT OF THE OEMISSIONS INTO THE ATMOSPHERE [Q-2r20#21, see R.R.Q., 1981, 8-7No. 1 No. 2 No. MICRO-RINGELMANN SCALE MINISTÈRE DE L’ENVIRONNEMENT GOUVERNEMENT DU QUÉBEC [Q-2r20#21, FIN] Definitions1. Select an observation point situated at more thametres from the source of emission. 
2. Avoid looking towards bright sunlight and select an observation angle free of 

dark objects in the background. 3. Hold the chart at arm's length and look at the emission through the slip. 4. Record the scale number corresponding to the opacity, including the number 0 corresponding to white over white. 5. To calculate the opacity of an emission record the numbered shades on the scale and use the following formula: [Q-2r20#22, see R.R.Q., 1981, 8-731] P= NEU at opacity No. 1 X 20%  number of observations [Q-2r20#22, FIN] where P designates the percentage of opacity of the emissions and NEU designates the number of equivalent units. The number of each numbered shade constitutes as many equivalent units. 6. Only one observation is enough for the enforcement of section 10. R.R.Q., 1981, c. Q-2, r. 20, Sch. C. R.R.Q., 1981, c. Q-2, r. 20 O.C. 240-85, 1985 G.O. 2, 1011 O.C. 1004-85, 1985 G.O. 2, 2043 O.C. 187-88, 1988 G.O. 2, 1267 O.C. 715-90, 1990 G.O. 2, 1422 O.C. 584-92, 1992 G.O. 2, 2517 O.C. 1544-92, 1992 G.O. 2, 4863 O.C. 448-96, 1996 G.O. 2, 2107 O.C. 1310-97, 1997 G.O. 2, 5199 O.C. 492-2000, 2000 G.O. 2, 2090 
ATTACHMENT R 

RBLC Taconite Industry Query Results 
DETAILED SOURCE LISTING 

Report Date: 04/15/2003 

Facility Information

RBLC ID: MN-0036 (final) Date Last UpdatedCompany Name: ISPAT INLAND MINING CO. Permit/File No.: Plant Name: ISPAT INLAND MINING CO. Permit Date: EPA Region: 5 SIC Code: County/State: ST. LOUIS / MN NAICS: Permit Issued By: MINNESOTA POLL CTRL AGCY, AIR QUAL DIV (agency) 

HONGMING JIANG (contact) 651-296-7670

Plant Description: TACONITE PROCESSINGNotes: A Psd Permit, Issued on 9/25/87, Gave an Erroneous Nox Emission Limit for the Indurating Machine, Which Wou

Burners. It Is Now Corrected with the Facility's Title V Permit, after a Thorough Backward- Looking PSD Review

Without Any New Add-on Control.

Process/Pollutant Information 

PROCESS: METAL ORE MINING, TACONITE, INDURATING FURNACEProcess Type: 90.031 (Taconite Iron Ore Processing)Primary Fuel: NATURAL GAS SCC Code: 30302312Throughput: 370 MMBTU/H Compliance Verified: NoProcess Notes: ADDITIONAL THROUGHPUT: 400 T PELLETS/HR. MAIN BURNERS ARE GAS FIRED WITH OIL AS BACK

BURNERS ARE GAS FIRED ONLY. FERROUS IRON IN TACONITE HELPS REDUCE ENERGY DEMAND. BUCONTENT CANNOT BE CONTROLLED. TESTING INCLUDES PRODUCTION AND FUEL USE DATA OVER AVERAGE. ONLY NO2 REQUIRED BACT DETERMINATION.

POLLUTANT: NO2 CAS No.: 10102-44-0

Emission Limit 1: 1088 LB/H Basis: BACT-PSDEmission Limit 2: % Efficiency:Standard Emission:Control Method: (P) FUEL USE IS LIMITED TO 270 MMBTU/HR FOR ALL EU26 BURNERS COMBINE

STACKS) IN ADDITION TO THE USE OF EXISTING LOW NOX BURNERS. 11 CONTOPTIONS EXAMINED.

Pollutant Notes:
ATTACHMENT S 

August 25, 2003, Barr Memorandum “CALPUFF Screening Protocol for 

Taconite Industry BART Project” sans Attachments 
 

Memorandum

To: Stuart Arkley and Margaret McCourtney, MPCA 

From: Joel Trinkle and Eric Edwalds, Barr 

Subject: CALPUFF Screening Protocol for Taconite Industry BART Project

Date: August 25, 2003 

Project: 23/62-833-BART-OP2

c: 

Pursuant to a request made during our phone call with Ms. McCourtney on August 18, Barr is providing 

for your review a visibility screening protocol with parameter values that we propose to use in CALPUFF 

for modeling taconite industry BART-eligible sources. To conserve time, this protocol highlights the 

primary aspects of the modeling analysis in a memorandum rather than in a formal report. 

Objective 

The purpose of the visibility screening effort is to better understand the pollutants of concern for visibility 

from the taconite industry as well as to inform the taconite industry on visibility impacts from the its 

emission sources. 

Modeling Program 

The CALMET/CALPUFF/CALPOST system will be used in this analysis. Attachment A contains an 

example CALPUFF input file with the proposed control options to be used in the analysis. The source 

input data will be added to the control file upon approval to begin work. The CALMET component of the 

model was conducted for a previous client; Attachment B contains a CALMET input file. The previous 

CALPUFF and CALMET analysis was approved in general by John Notar of the National Park Service 

before the project was subsequently cancelled. 

Sources 

Consistent with Table 5-1 of the draft Taconite BART Report (July 11, 2003), four ‘typical’ sources will 

be modeled: grate/kiln furnace, straight grate furnace, pellet cooler, and ore handling. One representative 

Barr Engineering Company 

4700 West 77th Street • Minneapolis, MN 55435-4803 

Phone: 952-832-2600 • Fax: 952-832-2601 

Minneapolis, MN • Hibbing, MN • Duluth, MN • Ann Arbor, MI • Jefferson City, MO 
To: Stuart Arkley and Margaret McCourtney, MPCA 

From: Joel Trinkle and Eric Edwalds, Barr 

Subject: CALPUFF Screening Protocol for Taconite Industry BART Project 

Date: August 25, 2003 

Project: 23/62-833-BART-OP2 

c: 

2 

stack will be used for each of the sources, for a total of four modeled sources. The following table 

contains the stack parameters that will be used in the modeling. Flow rate and temperature parameters 

were taken from Table 5-1. The stack height and stack diameter parameters were estimated from taconite 

source data in the MPCA Delta Database. All of the stack parameters represent a typical stack 

configuration rather than a “worst-case” stack. 

Taconite BART Study 

CALPUFF Stack Parameters 

English Units 

Height Temperature Flow Diameter 

Ft F acfm Ft 

Straight Grate Furnace 140 135 188,865 8 

Grate/Kiln Furnace 140 135 377,730 13 

Pellet Cooler 135 800 239,425 13 

Ore Handling 80 77 7,143 2 

 

Metric Units 

Height Temperature Velocity Diameter 

Source Type M K m/s m 

Straight Grate Furnace 42.7 330 19 2.4 

Grate/Kiln Furnace 42.7 330 14 4.0 

Pellet Cooler 41.1 700 9 4.0 

Ore Handling 24.4 298 12 0.6 

Stack parameters for temperature and velocity (Normal Flow acfm) from Table 5-1 "Taconite 

Model Source Characteristics for BART Screening Evaluation" 

Stack parameters for height and diameter are approximate average values estimated from stack 

data in MPCA Delta Database. 

 

We will not model fugitive sources for the following reasons: 

• Only one facility included fugitive sources in the BART-eligible survey, indicating that most 

fugitive sources are either not BART-eligible or were specifically excluded in the survey. 
To: Stuart Arkley and Margaret McCourtney, MPCA 

From: Joel Trinkle and Eric Edwalds, Barr 

Subject: CALPUFF Screening Protocol for Taconite Industry BART Project 

Date: August 25, 2003 

Project: 23/62-833-BART-OP2 

c: 

3 

• Fugitive emissions tend to be coarse particulates, which in generanl are not the drivers for 

visibility degradation as compared to sulfates, nitrates, and fine particulate matter. 

• All of the taconite facilities have fugitive dust control plans, as described in the draft BART 

report; therefore, BART for fugitive sources would likely not be different from what is already 

in the fugitive dust control plans. 

Pollutants 

CALPUFF allows for the specification of the pollutants to be modeled (Input Group 3A, 3B). Because 

there is limited information on the pollutants to be modeled, we propose the following: 

 Dry OUTPUT GROUP 

 SPECIES MODELED EMITTED DEPOSITED NUMBER 

 NAME (0=NO, 1=YES) (0=NO, 1=YES) (0=NO, (0=NONE, 

 (Limit: 12 1=COMPUTED-GAS 1=1st CGRUP, 

 Characters 2=COMPUTED-PARTICLE 2=2nd CGRUP, 

 in length) 3=USER-SPECIFIED) 3= etc.) 

! SO2 = 1, 1, 1, 0 ! 

! SO4 = 1, 0, 2, 0 ! 

! NOX = 1, 1, 1, 0 ! 

! HNO3 = 1, 0, 1, 0 ! 

! NO3 = 1, 0, 2, 0 ! 

! PMC = 1, 1, 2, 0 ! 

Absent from the above pollutant list are fine particulates and elemental carbon due to lack of adequate 

emissions data. 
To: Stuart Arkley and Margaret McCourtney, MPCA 

From: Joel Trinkle and Eric Edwalds, Barr 

Subject: CALPUFF Screening Protocol for Taconite Industry BART Project 

Date: August 25, 2003 

Project: 23/62-833-BART-OP2 

c: 

4 

Emission Rates: 

Pre-BART Scenario

Only the four sources identified in Table 5-1 of the draft BART report will be included in the modeling. 

Only one pre-BART scenario will be modeled. Total industry emissions will be based on the 2001 

emission inventory total (in Table 3-2 of the draft BART report) divided by a 0.85 capacity factor 

referenced in Hongming Jiang’s paper on the taconite industry. The scaled-up 2001 industry emission 

totals will be apportioned into the four sources as shown in the table below, which reflect emissions from 

the source categories. 

Post-BART Scenario

The post-BART emission rates will be equal to the pre-BART emission rates times the appropriate control 

efficiency for the selected BART. Some of the BART-eligible sources already have controls that would 

likely meet BART, so the incremental control efficiency dictated by BART for the taconite industry will 

likely be less than that shown for the individual control technologies in Table 6-1 of the draft BART 

report. Barr proposes to use a 30% reduction in NOx, SO2, and PM10 emission rates for the post-BART 

scenario. This is an estimate that will help provide an idea of the visibility reduction in relationship to an 

emissions reduction. It should not be construed to be an expected emissions reduction from the taconite 

industry due to application of BART. 

Source Pre-BART Emissions (tons) Post-BART Emissions (tons) 

 PM10 SO2 NOx PM10 SO2 NOx 

Grate/Kiln 4595 6693 21395 3217 4685 14977 

Straight Grate 358 331 4396 251 232 3077 

Pellet Cooler 195 -- -- 137 -- -- 

Ore Handling 1027 -- -- 719 -- -- 

We are not considering additional modeling scenarios for the following reasons: 

• The modeling has limited application. The purpose of the visibility screening effort is to better 

understand the pollutants of concern for visibility from the taconite industry as well as to inform 

the taconite industry on visibility impacts from the its emission sources. 
To: Stuart Arkley and Margaret McCourtney, MPCA 

From: Joel Trinkle and Eric Edwalds, Barr 

Subject: CALPUFF Screening Protocol for Taconite Industry BART Project 

Date: August 25, 2003 

Project: 23/62-833-BART-OP2 

c: 

5 

• Simplifying assumptions that are made in the protocol introduce variability on an equal or greater 

scale than considering different emission scenarios. 

Model Control Selections 

The model receptor grid and location of the single plant to be modeled is illustrated as a figure in 

Attachment C. The base elevation for the modeled plant will be 475 m, which is the average of the five 

plants on the Mesabi range. Building downwash will not be included in the model. Barr will model one 

year of meteorological data (December 1984 through November 1985). Deposition will be included in 

the modeling. Other sources (non-taconite) will not be included in the modeling. We will use default 

values for the chemistry parameters with the following exceptions that were approved in a previous 

analysis by National Park Service: 

 Ozone Background: 40 ppm (default is 80) 

Ammonia Background: 1 ppm (default is 10) 

Results and Reporting 

The purpose of the modeling is to assess the change in visibility due to the application of BART at the 

taconite facilities. The only change between the two model runs will be the emission rates for PM10, 

SO2 and NOx. Attachment D is an example spreadsheet file that will be developed for reporting the 

visibility results. One spreadsheet will be developed for each of the two scenario (pre- and post-BART), 

and the differences between the spreadsheets will be summarized in an additional spreadsheet table. 

The results will be reported in the Taconite BACT Report, including a brief description of the modeling 

and model results. 
ATTACHMENT T 

CALMET Input File (One of Four Files) 
MetQ01.inp

MPCA Taconite BART Study

50 x 33 5 km meteorological grid

Q01 (12/1/84-2/28/85)

---------------- Run title (3 lines) ------------------------------------------

 CALMET MODEL CONTROL FILE

 --------------------------

-------------------------------------------------------------------------------

INPUT GROUP: 0 -- Input and Output File Names

Subgroup (a)

------------

Default Name Type File Name

------------ ---- ---------

GEO.DAT input ! GEODAT=C:\CALMETND\GEO.DAT !

SURF.DAT input ! SRFDAT=L:\CALMET\SURFACE\SURF.DAT !

CLOUD.DAT input * CLDDAT= *

PRECIP.DAT input ! PRCDAT=L:\CALMET\PRECIP\PRECIP.DAT !

MM4.DAT input * MM4DAT= *

WT.DAT input * WTDAT= *

CALMET.LST output ! METLST=L:\CALMET\OUTPUTB2\METQ01.LST !

CALMET.DAT output ! METDAT=L:\CALMET\OUTPUTB2\METQ01.DAT !

PACOUT.DAT output * PACDAT= *

All file names will be converted to lower case if LCFILES = T

Otherwise, if LCFILES = F, file names will be converted to UPPER CASE

 T = lower case ! LCFILES = T !

 F = UPPER CASE

NUMBER OF UPPER AIR & OVERWATER STATIONS:

 Number of upper air stations (NUSTA) No default ! NUSTA = 3 !

 Number of overwater met stations

 (NOWSTA) No default ! NOWSTA = 0 !

 !END!

--------------------------------------------------------------------------------

Subgroup (b)

---------------------------------

Upper air files (one per station)

---------------------------------

Default Name Type File Name

------------ ---- ---------

UP1.DAT input 1 ! UPDAT=L:\CALMET\UPPER\UPSTCQ01.DAT! !END!

UP2.DAT input 2 ! UPDAT=L:\CALMET\UPPER\UPINLQ01.DAT! !END!

UP3.DAT input 3 ! UPDAT=L:\CALMET\UPPER\UPGRBQ01.DAT! !END!

--------------------------------------------------------------------------------

Subgroup (c)

-----------------------------------------

Overwater station files (one per station)

-----------------------------------------

Default Name Type File Name

------------ ---- ---------

--------------------------------------------------------------------------------

Subgroup (d)

----------------

Other file names

----------------

Page 1
MetQ01.inp

Default Name Type File Name

------------ ---- ---------

DIAG.DAT input * DIADAT= *

PROG.DAT input * PRGDAT= *

TEST.PRT output * TSTPRT= *

TEST.OUT output * TSTOUT= *

TEST.KIN output * TSTKIN= *

TEST.FRD output * TSTFRD= *

TEST.SLP output * TSTSLP= *

--------------------------------------------------------------------------------

NOTES: (1) File/path names can be up to 70 characters in length

 (2) Subgroups (a) and (d) must have ONE 'END' (surround by

 delimiters) at the end of the group

 (3) Subgroups (b) and (c) must have an 'END' (surround by

 delimiters) at the end of EACH LINE

 !END!

-------------------------------------------------------------------------------

INPUT GROUP: 1 -- General run control parameters

--------------

 Starting date: Year (IBYR) -- No default ! IBYR= 1984 !

 Month (IBMO) -- No default ! IBMO= 12 !

 Day (IBDY) -- No default ! IBDY= 1 !

 Hour (IBHR) -- No default ! IBHR= 1 !

 Base time zone (IBTZ) -- No default ! IBTZ= 6 !

 PST = 08, MST = 07

 CST = 06, EST = 05

 Length of run (hours) (IRLG) -- No default ! IRLG= 2160 !

 Run type (IRTYPE) -- Default: 1 ! IRTYPE= 1 !

 0 = Computes wind fields only

 1 = Computes wind fields and micrometeorological variables

 (u*, w*, L, zi, etc.)

 (IRTYPE must be 1 to run CALPUFF or CALGRID)

 Compute special data fields required

 by CALGRID (i.e., 3-D fields of W wind

 components and temperature)

 in additional to regular Default: T ! LCALGRD = F !

 fields ? (LCALGRD)

 (LCALGRD must be T to run CALGRID)

 Flag to stop run after

 SETUP phase (ITEST) Default: 2 ! ITEST= 2 !

 (Used to allow checking

 of the model inputs, files, etc.)

 ITEST = 1 - STOPS program after SETUP phase

 ITEST = 2 - Continues with execution of

 COMPUTATIONAL phase after SETUP

!END!

-------------------------------------------------------------------------------

Page 2
MetQ01.inp

INPUT GROUP: 2 -- Grid control parameters

--------------

 HORIZONTAL GRID DEFINITION:

 No. X grid cells (NX) No default ! NX = 50 !

 No. Y grid cells (NY) No default ! NY = 33 !

 GRID SPACING (DGRIDKM) No default ! DGRIDKM = 6. !

 Units: km

 REFERENCE COORDINATES

 of SOUTHWEST corner of grid cell (1,1)

 X coordinate (XORIGKM) No default ! XORIGKM = 453.368 !

 Y coordinate (YORIGKM) No default ! YORIGKM = 5217.226 !

 Units: km

 Latitude (XLAT0) No default ! XLAT0 = 47.109 !

 Longitude (XLON0) No default ! XLON0 = 93.614 !

 UTM ZONE (IUTMZN) Default: 0 ! IUTMZN = 15 !

 LAMBERT CONFORMAL PARAMETERS

 Rotate input winds from true north to

 map north using a Lambert conformal

 projection? (LLCONF) Default: F ! LLCONF = F !

 Latitude of 1st standard parallel Default: 30. ! XLAT1 = 30.000 !

 Latitude of 2nd standard parallel Default: 60. ! XLAT2 = 60.000 !

 (XLAT1 and XLAT2; + in NH, - in SH)

 Longitude (RLON0) Default = 90. ! RLON0 = 90.000 !

 (used only if LLCONF = T)

 (Positive = W. Hemisphere;

 Negative = E. Hemisphere)

 Origin Latitude (RLAT0) Default = 40. ! RLAT0 = 40.000 !

 (used only if IPROG > 2)

 (Positive = N. Hemisphere;

 Negative = S. Hemisphere)

 Vertical grid definition:

 No. of vertical layers (NZ) No default ! NZ = 10 !

 Cell face heights in arbitrary

 vertical grid (ZFACE(NZ+1)) No defaults

 Units: m

 ! ZFACE = 0.,20.,50.,100.,200.,400.,800.,1200.,1600.,2000.,3600. !

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 3 -- Output Options

--------------

 DISK OUTPUT OPTION

 Save met. fields in an unformatted

 output file ? (LSAVE) Default: T ! LSAVE = T !

Page 3
MetQ01.inp

 (F = Do not save, T = Save)

 Type of unformatted output file:

 (IFORMO) Default: 1 ! IFORMO = 1 !

 1 = CALPUFF/CALGRID type file (CALMET.DAT)

 2 = MESOPUFF-II type file (PACOUT.DAT)

 LINE PRINTER OUTPUT OPTIONS:

 Print met. fields ? (LPRINT) Default: F ! LPRINT = F !

 (F = Do not print, T = Print)

 (NOTE: parameters below control which

 met. variables are printed)

 Print interval

 (IPRINF) in hours Default: 1 ! IPRINF = 24 !

 (Meteorological fields are printed

 every 24 hours)

 Specify which layers of U, V wind component

 to print (IUVOUT(NZ)) -- NOTE: NZ values must be entered

 (0=Do not print, 1=Print)

 (used only if LPRINT=T) Defaults: NZ*0 

 ! IUVOUT = 0 , 0 , 0 , 1 , 0 , 0 , 0 , 0 , 0 , 0 !

 -----------------------

 Specify which levels of the W wind component to print

 (NOTE: W defined at TOP cell face -- 6 values)

 (IWOUT(NZ)) -- NOTE: NZ values must be entered

 (0=Do not print, 1=Print)

 (used only if LPRINT=T & LCALGRD=T)

 -----------------------------------

 Defaults: NZ*0 

 ! IWOUT = 0 , 0 , 0 , 1 , 0 , 0 , 0 , 0 , 0 , 0 !

 Specify which levels of the 3-D temperature field to print

 (ITOUT(NZ)) -- NOTE: NZ values must be entered

 (0=Do not print, 1=Print)

 (used only if LPRINT=T & LCALGRD=T)

 -----------------------------------

 Defaults: NZ*0 

 ! ITOUT = 0 , 0 , 0 , 1 , 0 , 0 , 0 , 0 , 0 , 0 !

 Specify which meteorological fields

 to print

 (used only if LPRINT=T) Defaults: 0 (all variables)

 -----------------------

 Variable Print ?

 (0 = do not print,

 1 = print)

 -------- ------------------

 ! STABILITY = 1 ! - PGT stability class

 ! USTAR = 1 ! - Friction velocity

 ! MONIN = 1 ! - Monin-Obukhov length

 ! MIXHT = 1 ! - Mixing height

Page 4
MetQ01.inp

 ! WSTAR = 1 ! - Convective velocity scale

 ! PRECIP = 1 ! - Precipitation rate

 ! SENSHEAT = 1 ! - Sensible heat flux

 ! CONVZI = 1 ! - Convective mixing ht.

 Testing and debug print options for micrometeorological module

 Print input meteorological data and

 internal variables (LDB) Default: F ! LDB = F !

 (F = Do not print, T = print)

 (NOTE: this option produces large amounts of output)

 First time step for which debug data

 are printed (NN1) Default: 1 ! NN1 = 1 !

 Last time step for which debug data

 are printed (NN2) Default: 1 ! NN2 = 1 !

 Testing and debug print options for wind field module

 (all of the following print options control output to

 wind field module's output files: TEST.PRT, TEST.OUT,

 TEST.KIN, TEST.FRD, and TEST.SLP)

 Control variable for writing the test/debug

 wind fields to disk files (IOUTD)

 (0=Do not write, 1=write) Default: 0 ! IOUTD = 0 !

 Number of levels, starting at the surface,

 to print (NZPRN2) Default: 1 ! NZPRN2 = 0 !

 Print the INTERPOLATED wind components ?

 (IPR0) (0=no, 1=yes) Default: 0 ! IPR0 = 0 !

 Print the TERRAIN ADJUSTED surface wind

 components ?

 (IPR1) (0=no, 1=yes) Default: 0 ! IPR1 = 0 !

 Print the SMOOTHED wind components and

 the INITIAL DIVERGENCE fields ?

 (IPR2) (0=no, 1=yes) Default: 0 ! IPR2 = 0 !

 Print the FINAL wind speed and direction

 fields ?

 (IPR3) (0=no, 1=yes) Default: 0 ! IPR3 = 0 !

 Print the FINAL DIVERGENCE fields ?

 (IPR4) (0=no, 1=yes) Default: 0 ! IPR4 = 0 !

 Print the winds after KINEMATIC effects

 are added ?

 (IPR5) (0=no, 1=yes) Default: 0 ! IPR5 = 0 !

 Print the winds after the FROUDE NUMBER

 adjustment is made ?

 (IPR6) (0=no, 1=yes) Default: 0 ! IPR6 = 0 !

 Print the winds after SLOPE FLOWS

 are added ?

 (IPR7) (0=no, 1=yes) Default: 0 ! IPR7 = 0 !

 Print the FINAL wind field components ?

Page 5
MetQ01.inp

 (IPR8) (0=no, 1=yes) Default: 0 ! IPR8 = 0 !

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 4 -- Meteorological data options

--------------

 NUMBER OF SURFACE & PRECIP. METEOROLOGICAL STATIONS

 Number of surface stations (NSSTA) No default ! NSSTA = 6 !

 Number of precipitation stations

 (NPSTA) No default ! NPSTA = 14 !

 CLOUD DATA OPTIONS

 Griddid cloud fields:

 (ICLOUD) Default: 0 ! ICLOUD = 0 !

 ICLOUD = 0 - Gridded clouds not used

 ICLOUD = 1 - Gridded CLOUD.DAT generated as OUTPUT

 ICLOUD = 2 - Gridded CLOUD.DAT read as INPUT

 FILE FORMATS

 Surface meteorological data file format

 (IFORMS) Default: 2 ! IFORMS = 2 !

 (1 = unformatted (e.g., SMERGE output))

 (2 = formatted (free-formatted user input))

 Precipitation data file format

 (IFORMP) Default: 2 ! IFORMP = 2 !

 (1 = unformatted (e.g., PMERGE output))

 (2 = formatted (free-formatted user input))

 Cloud data file format

 (IFORMC) Default: 2 ! IFORMC = 1 !

 (1 = unformatted - CALMET unformatted output)

 (2 = formatted - free-formatted CALMET output or user input)

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 5 -- Wind Field Options and Parameters

--------------

 WIND FIELD MODEL OPTIONS

 Model selection variable (IWFCOD) Default: 1 ! IWFCOD = 1 !

 0 = Objective analysis only

 1 = Diagnostic wind module

 Compute Froude number adjustment

 effects ? (IFRADJ) Default: 1 ! IFRADJ = 1 !

 (0 = NO, 1 = YES)

 Compute kinematic effects ? (IKINE) Default: 0 ! IKINE = 0 !

 (0 = NO, 1 = YES)

 Use O'Brien procedure for adjustment

Page 6
MetQ01.inp

 of the vertical velocity ? (IOBR) Default: 0 ! IOBR = 0 !

 (0 = NO, 1 = YES)

 Compute slope flow effects ? (ISLOPE) Default: 1 ! ISLOPE = 1 !

 (0 = NO, 1 = YES)

 Extrapolate surface wind observations

 to upper layers ? (IEXTRP) Default: -4 ! IEXTRP = -4 !

 (1 = no extrapolation is done,

 2 = power law extrapolation used,

 3 = user input multiplicative factors

 for layers 2 - NZ used (see FEXTRP array)

 4 = similarity theory used

 -1, -2, -3, -4 = same as above except layer 1 data

 at upper air stations are ignored

 Extrapolate surface winds even

 if calm? (ICALM) Default: 0 ! ICALM = 0 !

 (0 = NO, 1 = YES)

 Layer-dependent biases modifying the weights of

 surface and upper air stations (BIAS(NZ))

 -1<=BIAS<=1

 Negative BIAS reduces the weight of upper air stations

 (e.g. BIAS=-0.1 reduces the weight of upper air stations

 by 10%; BIAS= -1, reduces their weight by 100 %)

 Positive BIAS reduces the weight of surface stations

 (e.g. BIAS= 0.2 reduces the weight of surface stations

 by 20%; BIAS=1 reduces their weight by 100%)

 Zero BIAS leaves weights unchanged (1/R**2 interpolation)

 Default: NZ*0

 ! BIAS = 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 

0 !

 Minimum distance from nearest upper air station

 to surface station for which extrapolation

 of surface winds at surface station will be allowed

 (RMIN2: Set to -1 for IEXTRP = 4 or other situations

 where all surface stations should be extrapolated)

 Default: 4. ! RMIN2 = -1.0 !

 Use gridded prognostic wind field model

 output fields as input to the diagnostic

 wind field model (IPROG) Default: 0 ! IPROG = 0 !

 (0 = No, [IWFCOD = 0 or 1]

 1 = Yes, use CSUMM prog. winds as Step 1 field, [IWFCOD = 0]

 2 = Yes, use CSUMM prog. winds as initial guess field [IWFCOD = 1]

 3 = Yes, use winds from MM4.DAT file as Step 1 field [IWFCOD = 0]

 4 = Yes, use winds from MM4.DAT file as initial guess field [IWFCOD = 1]

 5 = Yes, use winds from MM4.DAT file as observations [IWFCOD = 1]

 13 = Yes, use winds from MM5.DAT file as Step 1 field [IWFCOD = 0]

 14 = Yes, use winds from MM5.DAT file as initial guess field [IWFCOD = 1]

 15 = Yes, use winds from MM5.DAT file as observations [IWFCOD = 1]

 RADIUS OF INFLUENCE PARAMETERS

 Use varying radius of influence Default: F ! LVARY = F!

 (if no stations are found within RMAX1,RMAX2,

 or RMAX3, then the closest station will be used)

 Maximum radius of influence over land

 in the surface layer (RMAX1) No default ! RMAX1 = 30. !

 Units: km

Page 7
MetQ01.inp

 Maximum radius of influence over land

 aloft (RMAX2) No default ! RMAX2 = 50. !

 Units: km

 Maximum radius of influence over water

 (RMAX3) No default ! RMAX3 = 500. !

 Units: km

 OTHER WIND FIELD INPUT PARAMETERS

 Minimum radius of influence used in

 the wind field interpolation (RMIN) Default: 0.1 ! RMIN = 1.0 !

 Units: km

 Radius of influence of terrain

 features (TERRAD) No default ! TERRAD = 10. !

 Units: km

 Relative weighting of the first

 guess field and observations in the

 SURFACE layer (R1) No default ! R1 = 10. !

 (R1 is the distance from an Units: km

 observational station at which the

 observation and first guess field are

 equally weighted)

 Relative weighting of the first

 guess field and observations in the

 layers ALOFT (R2) No default ! R2 = 25. !

 (R2 is applied in the upper layers Units: km

 in the same manner as R1 is used in

 the surface layer).

 Relative weighting parameter of the

 prognostic wind field data (RPROG) No default ! RPROG = 54. !

 (Used only if IPROG = 1) Units: km

 ------------------------

 Maximum acceptable divergence in the

 divergence minimization procedure

 (DIVLIM) Default: 5.E-6 ! DIVLIM= 5.0E-06 !

 Maximum number of iterations in the

 divergence min. procedure (NITER) Default: 50 ! NITER = 50 !

 Number of passes in the smoothing

 procedure (NSMTH(NZ))

 NOTE: NZ values must be entered

 Default: 2,(mxnz-1)*4 ! NSMTH = 

 2 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 !

 Maximum number of stations used in

 each layer for the interpolation of

 data to a grid point (NINTR2(NZ))

 NOTE: NZ values must be entered Default: 99. ! NINTR2 = 

 99 , 99 , 99 , 99 , 99 , 99, 99 , 99 , 99 , 99 !

 Critical Froude number (CRITFN) Default: 1.0 ! CRITFN = 1. !

 Empirical factor controlling the

 influence of kinematic effects

 (ALPHA) Default: 0.1 ! ALPHA = 0.1 !

 Multiplicative scaling factor for

Page 8
MetQ01.inp

 extrapolation of surface observations

 to upper layers (FEXTR2(NZ)) Default: NZ*0.0 

 ! FEXTR2 = 0., 0., 0., 0., 0., 0., 0., 0., 0., 0. !

 (Used only if IEXTRP = 3 or -3)

 BARRIER INFORMATION

 Number of barriers to interpolation

 of the wind fields (NBAR) Default: 0 ! NBAR = 0 !

 THE FOLLOWING 4 VARIABLES ARE INCLUDED

 ONLY IF NBAR > 0

 NOTE: NBAR values must be entered No defaults

 for each variable Units: km

 X coordinate of BEGINNING

 of each barrier (XBBAR(NBAR)) ! XBBAR = 0. !

 Y coordinate of BEGINNING

 of each barrier (YBBAR(NBAR)) ! YBBAR = 0. !

 X coordinate of ENDING

 of each barrier (XEBAR(NBAR)) ! XEBAR = 0. !

 Y coordinate of ENDING

 of each barrier (YEBAR(NBAR)) ! YEBAR = 0. !

 DIAGNOSTIC MODULE DATA INPUT OPTIONS

 Surface temperature (IDIOPT1) Default: 0 ! IDIOPT1 = 0 !

 0 = Compute internally from

 hourly surface observations

 1 = Read preprocessed values from

 a data file (DIAG.DAT)

 Surface met. station to use for

 the surface temperature (ISURFT) No default ! ISURFT = 4 !

 (Must be a value from 1 to NSSTA)

 (Used only if IDIOPT1 = 0)

 --------------------------

 Domain-averaged temperature lapse

 rate (IDIOPT2) Default: 0 ! IDIOPT2 = 0 !

 0 = Compute internally from

 twice-daily upper air observations

 1 = Read hourly preprocessed values

 from a data file (DIAG.DAT)

 Upper air station to use for

 the domain-scale lapse rate (IUPT) No default ! IUPT = 2 !

 (Must be a value from 1 to NUSTA)

 (Used only if IDIOPT2 = 0)

 --------------------------

 Depth through which the domain-scale

 lapse rate is computed (ZUPT) Default: 200. ! ZUPT = 200. !

 (Used only if IDIOPT2 = 0) Units: meters

 --------------------------

 Domain-averaged wind components

 (IDIOPT3) Default: 0 ! IDIOPT3 = 0 !

 0 = Compute internally from

 twice-daily upper air observations

Page 9
MetQ01.inp

 1 = Read hourly preprocessed values

 a data file (DIAG.DAT)

 Upper air station to use for

 the domain-scale winds (IUPWND) Default: -1 ! IUPWND = -1 !

 (Must be a value from -1 to NUSTA)

 (Used only if IDIOPT3 = 0)

 --------------------------

 Bottom and top of layer through

 which the domain-scale winds

 are computed

 (ZUPWND(1), ZUPWND(2)) Defaults: 1., 1000. ! ZUPWND= 1., 1000. !

 (Used only if IDIOPT3 = 0) Units: meters

 --------------------------

 Observed surface wind components

 for wind field module (IDIOPT4) Default: 0 ! IDIOPT4 = 0 !

 0 = Read WS, WD from a surface

 data file (SURF.DAT)

 1 = Read hourly preprocessed U, V from

 a data file (DIAG.DAT)

 Observed upper air wind components

 for wind field module (IDIOPT5) Default: 0 ! IDIOPT5 = 0 !

 0 = Read WS, WD from an upper

 air data file (UP1.DAT, UP2.DAT, etc.)

 1 = Read hourly preprocessed U, V from

 a data file (DIAG.DAT)

 LAKE BREEZE INFORMATION

 Use Lake Breeze Module (LLBREZE)

 Default: F ! LLBREZE = F !

 Number of lake breeze regions (NBOX) ! NBOX = 0 !

 X Grid line 1 defining the region of interest

 ! XG1 = 0. !

 X Grid line 2 defining the region of interest

 ! XG2 = 0. !

 Y Grid line 1 defining the region of interest

 ! YG1 = 0. !

 Y Grid line 2 defining the region of interest

 ! YG2 = 0. !

 X Point defining the coastline (Straight line)

 (XBCST) (KM) Default: none ! XBCST = 0. !

 Y Point defining the coastline (Straight line)

 (YBCST) (KM) Default: none ! YBCST = 0. !

 X Point defining the coastline (Straight line)

 (XECST) (KM) Default: none ! XECST = 0. !

 Y Point defining the coastline (Straight line)

 (YECST) (KM) Default: none ! YECST = 0. !

 Number of stations in the region Default: none ! NLB = *1 !* 

 (Surface stations + upper air stations)

 Station ID's in the region (METBXID(NLB))

Page 10
MetQ01.inp

 (Surface stations first, then upper air stations)

 ! METBXID = *0 !*

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 6 -- Mixing Height, Temperature and Precipitation Parameters

--------------

 EMPIRICAL MIXING HEIGHT CONSTANTS

 Neutral, mechanical equation

 (CONSTB) Default: 1.41 ! CONSTB = 1.41 !

 Convective mixing ht. equation

 (CONSTE) Default: 0.15 ! CONSTE = 0.15 !

 Stable mixing ht. equation

 (CONSTN) Default: 2400. ! CONSTN = 2400.!

 Overwater mixing ht. equation

 (CONSTW) Default: 0.16 ! CONSTW = 0.16 !

 Absolute value of Coriolis

 parameter (FCORIOL) Default: 1.E-4 ! FCORIOL = 1.0E-04!

 Units: (1/s)

 SPATIAL AVERAGING OF MIXING HEIGHTS

 Conduct spatial averaging

 (IAVEZI) (0=no, 1=yes) Default: 1 ! IAVEZI = 1 !

 Max. search radius in averaging

 process (MNMDAV) Default: 1 ! MNMDAV = 10 !

 Units: Grid

 cells

 Half-angle of upwind looking cone

 for averaging (HAFANG) Default: 30. ! HAFANG = 30. !

 Units: deg.

 Layer of winds used in upwind

 averaging (ILEVZI) Default: 1 ! ILEVZI = 1 !

 (must be between 1 and NZ)

 OTHER MIXING HEIGHT VARIABLES

 Minimum potential temperature lapse

 rate in the stable layer above the

 current convective mixing ht. Default: 0.001 ! DPTMIN = 0.001 !

 (DPTMIN) Units: deg. K/m

 Depth of layer above current conv.

 mixing height through which lapse Default: 200. ! DZZI = 200. !

 rate is computed (DZZI) Units: meters

 Minimum overland mixing height Default: 50. ! ZIMIN = 50. !

 (ZIMIN) Units: meters

 Maximum overland mixing height Default: 3000. ! ZIMAX = 3000. !

 (ZIMAX) Units: meters

 Minimum overwater mixing height Default: 50. ! ZIMINW = 50. !

 (ZIMINW) -- (Not used if observed Units: meters

 overwater mixing hts. are used)

 Maximum overwater mixing height Default: 3000. ! ZIMAXW = 3000. !

 (ZIMAXW) -- (Not used if observed Units: meters

 overwater mixing hts. are used)

Page 11
MetQ01.inp

 TEMPERATURE PARAMETERS

 Interpolation type

 (1 = 1/R ; 2 = 1/R**2) Default:1 ! IRAD = 1 !

 Radius of influence for temperature

 interpolation (TRADKM) Default: 500. ! TRADKM = 100. !

 Units: km

 Maximum Number of stations to include

 in temperature interpolation (NUMTS) Default: 5 ! NUMTS = 5 !

 Conduct spatial averaging of temp-

 eratures (IAVET) (0=no, 1=yes) Default: 1 ! IAVET = 1 !

 (will use mixing ht MNMDAV,HAFANG

 so make sure they are correct)

 Default temperature gradient Default: -.0098 ! TGDEFB = -0.0098 !

 below the mixing height over

 water (K/m) (TGDEFB)

 Default temperature gradient Default: -.0045 ! TGDEFA = -0.0045 !

 above the mixing height over

 water (K/m) (TGDEFA)

 Beginning (JWAT1) and ending (JWAT2)

 land use categories for temperature ! JWAT1 = 999 !

 interpolation over water -- Make ! JWAT2 = 999 !

 bigger than largest land use to disable

 PRECIP INTERPOLATION PARAMETERS

 Method of interpolation (NFLAGP) Default = 2 ! NFLAGP = 2 !

 (1=1/R,2=1/R**2,3=EXP/R**2)

 Radius of Influence (km) (SIGMAP) Default = 100.0 ! SIGMAP = 50. !

 (0.0 => use half dist. btwn

 nearest stns w & w/out

 precip when NFLAGP = 3)

 Minimum Precip. Rate Cutoff (mm/hr) Default = 0.01 ! CUTP = 0.01 !

 (values < CUTP = 0.0 mm/hr)

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 7 -- Surface meteorological station parameters

--------------

 SURFACE STATION VARIABLES

 (One record per station -- 6 records in all)

 1 2

 Name ID X coord. Y coord. Time Anem.

 (km) (km) zone Ht.(m)

 ----------------------------------------------------------

! SS1 ='GRB ' 14898 887.021 4936.896 6 9.1 !

! SS2 ='DLH ' 14913 559.739 5186.731 6 6.4 !

! SS3 ='FAR ' 14914 209.459 5204.611 6 8.5 !

! SS4 ='INL ' 14918 470.490 5379.135 6 6.1 !

! SS5 ='MSP ' 14922 481.572 4969.823 6 10 !

! SS6 ='EAC ' 14991 356.736 657.833 6 10 !

-------------------

Page 12
MetQ01.inp

 1

 Four character string for station name

 (MUST START IN COLUMN 9)

 2

 Five digit integer for station ID

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 8 -- Upper air meteorological station parameters

--------------

 UPPER AIR STATION VARIABLES

 (One record per station -- 3 records in all)

 1 2

 Name ID X coord. Y coord. Time zone

 (km) (km) 

 -----------------------------------------------

! US1 ='STC ' 14926 418.037 5044.388 6 !

! US2 ='INL ' 14918 470.490 5379.135 6 !

! US3 ='GRB ' 14898 887.021 4936.896 6 !

-------------------

 1

 Four character string for station name

 (MUST START IN COLUMN 9)

 2

 Five digit integer for station ID

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 9 -- Precipitation station parameters

--------------

 PRECIPITATION STATION VARIABLES

 (One record per station -- 14 records in all)

 (NOT INCLUDED IF NPSTA = 0)

 1 2

 Name Station X coord. Y coord.

 Code (km) (km)

 ------------------------------------

! PS1 ='BGF ' 210746 440.554 5338.615 !

! PS2 ='CLM ' 211589 394.499 5393.014 !

! PS3 ='DLH ' 212248 559.739 5186.731 !

! PS4 ='GFL ' 213417 657.437 5334.911 !

! PS5 ='HLO ' 213863 547.348 5145.878 !

! PS6 ='INL ' 214026 470.490 5379.135 !

! PS7 ='ORR ' 216213 511.179 5321.646 !

! PS8 ='PGD ' 216612 455.858 5232.897 !

! PS9 ='SLD ' 217460 475.835 5182.778 !

! PS10 ='TFT ' 218280 661.721 5270.157 !

! PS11 ='WLS ' 218613 598.373 5233.551 !

! PS12 ='WKR ' 218621 381.114 5217.253 !

! PS13 ='WBG ' 219059 419.563 5253.656 !

Page 13
MetQ01.inp

! PS14 ='WNT ' 219101 592.120 5309.405 !

-------------------

 1

 Four character string for station name

 (MUST START IN COLUMN 9)

 2

 Six digit station code composed of state

 code (first 2 digits) and station ID (last

 4 digits)

!END!

Page 14
ATTACHMENT U 

CALPUFF Input File (One of Six Files) 
p85prea.inp

MPCA Taconite BART Study - Pre-BART Emissions

Boundary Waters C. A. Wilderness (1-500) 

CALMET data - 12/1/84 through 11/30/85

---------------- Run title (3 lines) ------------------------------------------

 CALPUFF MODEL CONTROL FILE

 --------------------------

-------------------------------------------------------------------------------

INPUT GROUP: 0 -- Input and Output File Names

--------------

Default Name Type File Name

------------ ---- ---------

CALMET.DAT input * METDAT = *

 or

ISCMET.DAT input * ISCDAT = *

 or

PLMMET.DAT input * PLMDAT = *

 or

PROFILE.DAT input * PRFDAT = *

SURFACE.DAT input * SFCDAT = *

RESTARTB.DAT input * RSTARTB= *

--------------------------------------------------------------------------------

CALPUFF.LST output ! PUFLST =L:\CALPUFF\BART\OUTPUT\P85PREA.LST !

CONC.DAT output ! CONDAT =L:\CALPUFF\BART\OUTPUT\P85PREA.CON !

DFLX.DAT output ! DFDAT =L:\CALPUFF\BART\OUTPUT\P85PREA.DRY !

WFLX.DAT output ! WFDAT =L:\CALPUFF\BART\OUTPUT\P85PREA.WET !

VISB.DAT output ! VISDAT =L:\CALPUFF\BART\OUTPUT\P85PREA.VIS !

RESTARTE.DAT output * RSTARTE= *

--------------------------------------------------------------------------------

Emission Files

--------------

PTEMARB.DAT input * PTDAT = *

VOLEMARB.DAT input * VOLDAT = *

BAEMARB.DAT input * ARDAT = *

LNEMARB.DAT input * LNDAT = *

--------------------------------------------------------------------------------

Other Files

-----------

OZONE.DAT input * OZDAT = *

VD.DAT input * VDDAT = *

CHEM.DAT input * CHEMDAT= *

HILL.DAT input * HILDAT= *

HILLRCT.DAT input * RCTDAT= *

COASTLN.DAT input * CSTDAT= *

FLUXBDY.DAT input * BDYDAT= *

BCON.DAT input * BCNDAT= *

DEBUG.DAT output * DEBUG = *

MASSFLX.DAT output * FLXDAT= *

MASSBAL.DAT output * BALDAT= *

FOG.DAT output * FOGDAT= *

--------------------------------------------------------------------------------

All file names will be converted to lower case if LCFILES = T

Otherwise, if LCFILES = F, file names will be converted to UPPER CASE

 T = lower case ! LCFILES = F !

 F = UPPER CASE

NOTE: (1) file/path names can be up to 70 characters in length

Provision for multiple input files

Page 1
p85prea.inp

----------------------------------

 Number of CALMET.DAT files for run (NMETDAT)

 Default: 1 ! NMETDAT = 4 !

 Number of PTEMARB.DAT files for run (NPTDAT)

 Default: 0 ! NPTDAT = 0 !

 Number of BAEMARB.DAT files for run (NARDAT)

 Default: 0 ! NARDAT = 0 !

 Number of VOLEMARB.DAT files for run (NVOLDAT)

 Default: 0 ! NVOLDAT = 0 !

!END!

-------------

Subgroup (0a)

-------------

 The following CALMET.DAT filenames are processed in sequence if NMETDAT>1

Default Name Type File Name

------------ ---- ---------

 none input ! METDAT=L:\CALMET\OUTPUTB2\METQ01.DAT ! !END!

 none input ! METDAT=L:\CALMET\OUTPUTB2\METQ02.DAT ! !END!

 none input ! METDAT=L:\CALMET\OUTPUTB2\METQ03.DAT ! !END!

 none input ! METDAT=L:\CALMET\OUTPUTB2\METQ04.DAT ! !END!

--------------------------------------------------------------------------------

INPUT GROUP: 1 -- General run control parameters

--------------

 Option to run all periods found

 in the met. file (METRUN) Default: 0 ! METRUN = 0 !

 METRUN = 0 - Run period explicitly defined below

 METRUN = 1 - Run all periods in met. file

 Starting date: Year (IBYR) -- No default ! IBYR = 1984 !

 (used only if Month (IBMO) -- No default ! IBMO = 12 !

 METRUN = 0) Day (IBDY) -- No default ! IBDY = 1 !

 Hour (IBHR) -- No default ! IBHR = 1 !

 Length of run (hours) (IRLG) -- No default ! IRLG = 8760 !

 Number of chemical species (NSPEC)

 Default: 5 ! NSPEC = 6 !

 Number of chemical species

 to be emitted (NSE) Default: 3 ! NSE = 3 !

 Flag to stop run after

 SETUP phase (ITEST) Default: 2 ! ITEST = 2 !

 (Used to allow checking

 of the model inputs, files, etc.)

 ITEST = 1 - STOPS program after SETUP phase

 ITEST = 2 - Continues with execution of program

 after SETUP

 Restart Configuration:

Page 2
p85prea.inp

 Control flag (MRESTART) Default: 0 ! MRESTART = 0 !

 0 = Do not read or write a restart file

 1 = Read a restart file at the beginning of

 the run

 2 = Write a restart file during run

 3 = Read a restart file at beginning of run

 and write a restart file during run

 Number of periods in Restart

 output cycle (NRESPD) Default: 0 ! NRESPD = 0 !

 0 = File written only at last period

 >0 = File updated every NRESPD periods

 Meteorological Data Format (METFM)

 Default: 1 ! METFM = 1 !

 METFM = 1 - CALMET binary file (CALMET.MET)

 METFM = 2 - ISC ASCII file (ISCMET.MET)

 METFM = 3 - AUSPLUME ASCII file (PLMMET.MET)

 METFM = 4 - CTDM plus tower file (PROFILE.DAT) and

 surface parameters file (SURFACE.DAT)

 PG sigma-y is adjusted by the factor (AVET/PGTIME)**0.2

 Averaging Time (minutes) (AVET)

 Default: 60.0 ! AVET = 60. !

 PG Averaging Time (minutes) (PGTIME)

 Default: 60.0 ! PGTIME = 60. !

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 2 -- Technical options

--------------

 Vertical distribution used in the

 near field (MGAUSS) Default: 1 ! MGAUSS = 1 !

 0 = uniform

 1 = Gaussian

 Terrain adjustment method

 (MCTADJ) Default: 3 ! MCTADJ = 3 !

 0 = no adjustment

 1 = ISC-type of terrain adjustment

 2 = simple, CALPUFF-type of terrain

 adjustment

 3 = partial plume path adjustment

 Subgrid-scale complex terrain

 flag (MCTSG) Default: 0 ! MCTSG = 0 !

 0 = not modeled

 1 = modeled

 Near-field puffs modeled as

 elongated 0 (MSLUG) Default: 0 ! MSLUG = 0 !

 0 = no

 1 = yes (slug model used)

Page 3
p85prea.inp

 Transitional plume rise modeled ?

 (MTRANS) Default: 1 ! MTRANS = 1 !

 0 = no (i.e., final rise only)

 1 = yes (i.e., transitional rise computed)

 Stack tip downwash? (MTIP) Default: 1 ! MTIP = 1 !

 0 = no (i.e., no stack tip downwash)

 1 = yes (i.e., use stack tip downwash)

 Vertical wind shear modeled above

 stack top? (MSHEAR) Default: 0 ! MSHEAR = 0 !

 0 = no (i.e., vertical wind shear not modeled)

 1 = yes (i.e., vertical wind shear modeled)

 Puff splitting allowed? (MSPLIT) Default: 0 ! MSPLIT = 0 !

 0 = no (i.e., puffs not split)

 1 = yes (i.e., puffs are split)

 Chemical mechanism flag (MCHEM) Default: 1 ! MCHEM = 1 !

 0 = chemical transformation not

 modeled

 1 = transformation rates computed

 internally (MESOPUFF II scheme)

 2 = user-specified transformation

 rates used

 3 = transformation rates computed

 internally (RIVAD/ARM3 scheme)

 4 = secondary organic aerosol formation

 computed (MESOPUFF II scheme for OH)

 Wet removal modeled ? (MWET) Default: 1 ! MWET = 1 !

 0 = no

 1 = yes

 Dry deposition modeled ? (MDRY) Default: 1 ! MDRY = 1 !

 0 = no

 1 = yes

 (dry deposition method specified

 for each species in Input Group 3)

 Method used to compute dispersion

 coefficients (MDISP) Default: 3 ! MDISP = 3 !

 1 = dispersion coefficients computed from measured values

 of turbulence, sigma v, sigma w

 2 = dispersion coefficients from internally calculated

 sigma v, sigma w using micrometeorological variables

 (u*, w*, L, etc.)

 3 = PG dispersion coefficients for RURAL areas (computed using

 the ISCST multi-segment approximation) and MP coefficients in

 urban areas

 4 = same as 3 except PG coefficients computed using

 the MESOPUFF II eqns.

 5 = CTDM sigmas used for stable and neutral conditions.

 For unstable conditions, sigmas are computed as in

 MDISP = 3, described above. MDISP = 5 assumes that

 measured values are read

 Sigma-v/sigma-theta, sigma-w measurements used? (MTURBVW)

 (Used only if MDISP = 1 or 5) Default: 3 ! MTURBVW = 3 !

 1 = use sigma-v or sigma-theta measurements

 from PROFILE.DAT to compute sigma-y

Page 4
p85prea.inp

 (valid for METFM = 1, 2, 3, 4)

 2 = use sigma-w measurements

 from PROFILE.DAT to compute sigma-z

 (valid for METFM = 1, 2, 3, 4)

 3 = use both sigma-(v/theta) and sigma-w

 from PROFILE.DAT to compute sigma-y and sigma-z

 (valid for METFM = 1, 2, 3, 4)

 4 = use sigma-theta measurements

 from PLMMET.DAT to compute sigma-y

 (valid only if METFM = 3)

 Back-up method used to compute dispersion

 when measured turbulence data are

 missing (MDISP2) Default: 3 ! MDISP2 = 3 !

 (used only if MDISP = 1 or 5)

 2 = dispersion coefficients from internally calculated

 sigma v, sigma w using micrometeorological variables

 (u*, w*, L, etc.)

 3 = PG dispersion coefficients for RURAL areas (computed using

 the ISCST multi-segment approximation) and MP coefficients in

 urban areas

 4 = same as 3 except PG coefficients computed using

 the MESOPUFF II eqns.

 PG sigma-y,z adj. for roughness? Default: 0 ! MROUGH = 0 !

 (MROUGH)

 0 = no

 1 = yes

 Partial plume penetration of Default: 1 ! MPARTL = 1 !

 elevated inversion?

 (MPARTL)

 0 = no

 1 = yes

 Strength of temperature inversion Default: 0 ! MTINV = 0 !

 provided in PROFILE.DAT extended records?

 (MTINV)

 0 = no (computed from measured/default gradients)

 1 = yes

 PDF used for dispersion under convective conditions?

 Default: 0 ! MPDF = 0 !

 (MPDF)

 0 = no

 1 = yes

 Sub-Grid TIBL module used for shore line?

 Default: 0 ! MSGTIBL = 0 !

 (MSGTIBL)

 0 = no

 1 = yes

 Boundary conditions (concentration) modeled?

 Default: 0 ! MBCON = 0 !

 (MBCON)

 0 = no

 1 = yes

 Analyses of fogging and icing impacts due to emissions from

 arrays of mechanically-forced cooling towers can be performed

 using CALPUFF in conjunction with a cooling tower emissions

Page 5
p85prea.inp

 processor (CTEMISS) and its associated postprocessors. Hourly

 emissions of water vapor and temperature from each cooling tower

 cell are computed for the current cell configuration and ambient

 conditions by CTEMISS. CALPUFF models the dispersion of these

 emissions and provides cloud information in a specialized format

 for further analysis. Output to FOG.DAT is provided in either

 'plume mode' or 'receptor mode' format.

 Configure for FOG Model output?

 Default: 0 ! MFOG = 0 !

 (MFOG)

 0 = no

 1 = yes - report results in PLUME Mode format

 2 = yes - report results in RECEPTOR Mode format

 Test options specified to see if

 they conform to regulatory

 values? (MREG) Default: 1 ! MREG = 0 !

 0 = NO checks are made

 1 = Technical options must conform to USEPA values

 METFM 1

 AVET 60. (min)

 MGAUSS 1

 MCTADJ 3

 MTRANS 1

 MTIP 1

 MCHEM 1 (if modeling SOx, NOx)

 MWET 1

 MDRY 1

 MDISP 3

 MROUGH 0

 MPARTL 1

 SYTDEP 550. (m)

 MHFTSZ 0

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 3a, 3b -- Species list

-------------------

------------

Subgroup (3a)

------------

 The following species are modeled:

! CSPEC = SO2 ! !END!

! CSPEC = SO4 ! !END!

! CSPEC = NOX ! !END!

! CSPEC = HNO3 ! !END!

! CSPEC = NO3 ! !END!

! CSPEC = PMC ! !END!

 Dry OUTPUT 

GROUP

 SPECIES MODELED EMITTED DEPOSITED NUMBER

 NAME (0=NO, 1=YES) (0=NO, 1=YES) (0=NO, (0=NONE,

Page 6
p85prea.inp

 (Limit: 12 1=COMPUTED-GAS 1=1st 

CGRUP,

 Characters 2=COMPUTED-PARTICLE 2=2nd 

CGRUP,

 in length) 3=USER-SPECIFIED) 3= etc.)

! SO2 = 1, 1, 1, 0 !

! SO4 = 1, 0, 2, 0 !

! NOX = 1, 1, 1, 0 !

! HNO3 = 1, 0, 1, 0 !

! NO3 = 1, 0, 2, 0 !

! PMC = 1, 1, 2, 0 !

!END!

-------------

Subgroup (3b)

-------------

 The following names are used for Species-Groups in which results

 for certain species are combined (added) prior to output. The

 CGRUP name will be used as the species name in output files.

 Use this feature to model specific particle-size distributions

 by treating each size-range as a separate species.

 Order must be consistent with 3(a) above.

* CGRUP = PM10 * *END*

-------------------------------------------------------------------------------

INPUT GROUP: 4 -- Grid control parameters

--------------

METEOROLOGICAL grid:

 No. X grid cells (NX) No default ! NX = 50 !

 No. Y grid cells (NY) No default ! NY = 33 !

 No. vertical layers (NZ) No default ! NZ = 10 !

 Grid spacing (DGRIDKM) No default ! DGRIDKM = 6. !

 Units: km

 Cell face heights

 (ZFACE(nz+1)) No defaults

 Units: m

 ! ZFACE = 0., 20., 50., 100., 200., 400., 800., 1200., 1600., 2000.,

 3600. !

 Reference Coordinates

 of SOUTHWEST corner of

 grid cell(1, 1):

 X coordinate (XORIGKM) No default ! XORIGKM = 453.368 !

 Y coordinate (YORIGKM) No default ! YORIGKM = 5217.226 ! 

 Units: km

 UTM zone (IUTMZN) No default ! IUTMZN = 15 !

 Reference coordinates of CENTER

 of the domain (used in the

Page 7
p85prea.inp

 calculation of solar elevation

 angles)

 Latitude (deg.) (XLAT) No default ! XLAT = 47.989 !

 Longitude (deg.) (XLONG) No default ! XLONG = 91.632 !

 Time zone (XTZ) No default ! XTZ = 6.0 !

 (PST=8, MST=7, CST=6, EST=5)

Computational grid:

 The computational grid is identical to or a subset of the MET. grid.

 The lower left (LL) corner of the computational grid is at grid point

 (IBCOMP, JBCOMP) of the MET. grid. The upper right (UR) corner of the

 computational grid is at grid point (IECOMP, JECOMP) of the MET. grid.

 The grid spacing of the computational grid is the same as the MET. grid.

 X index of LL corner (IBCOMP) No default ! IBCOMP = 1 !

 (1 <= IBCOMP <= NX)

 Y index of LL corner (JBCOMP) No default ! JBCOMP = 1 !

 (1 <= JBCOMP <= NY)

 X index of UR corner (IECOMP) No default ! IECOMP = 50 !

 (1 <= IECOMP <= NX)

 Y index of UR corner (JECOMP) No default ! JECOMP = 33 !

 (1 <= JECOMP <= NY)

SAMPLING GRID (GRIDDED RECEPTORS):

 The lower left (LL) corner of the sampling grid is at grid point

 (IBSAMP, JBSAMP) of the MET. grid. The upper right (UR) corner of the

 sampling grid is at grid point (IESAMP, JESAMP) of the MET. grid.

 The sampling grid must be identical to or a subset of the computational

 grid. It may be a nested grid inside the computational grid.

 The grid spacing of the sampling grid is DGRIDKM/MESHDN.

 Logical flag indicating if gridded

 receptors are used (LSAMP) Default: T ! LSAMP = F !

 (T=yes, F=no)

 X index of LL corner (IBSAMP) No default ! IBSAMP = 1 !

 (IBCOMP <= IBSAMP <= IECOMP)

 Y index of LL corner (JBSAMP) No default ! JBSAMP = 1 !

 (JBCOMP <= JBSAMP <= JECOMP)

 X index of UR corner (IESAMP) No default ! IESAMP = 50 !

 (IBCOMP <= IESAMP <= IECOMP)

 Y index of UR corner (JESAMP) No default ! JESAMP = 33 !

 (JBCOMP <= JESAMP <= JECOMP)

 Nesting factor of the sampling

 grid (MESHDN) Default: 1 ! MESHDN = 1 !

 (MESHDN is an integer >= 1)

Page 8
p85prea.inp

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 5 -- Output Options

--------------

 * *

 FILE DEFAULT VALUE VALUE THIS RUN

 ---- ------------- --------------

 Concentrations (ICON) 1 ! ICON = 1 !

 Dry Fluxes (IDRY) 1 ! IDRY = 1 !

 Wet Fluxes (IWET) 1 ! IWET = 1 !

 Relative Humidity (IVIS) 1 ! IVIS = 1 !

 (relative humidity file is

 required for visibility

 analysis)

 Use data compression option in output file?

 (LCOMPRS) Default: T ! LCOMPRS = T !

 *

 0 = Do not create file, 1 = create file

 DIAGNOSTIC MASS FLUX OUTPUT OPTIONS:

 Mass flux across specified boundaries

 for selected species reported hourly?

 (IMFLX) Default: 0 ! IMFLX = 0 !

 0 = no

 1 = yes (FLUXBDY.DAT and MASSFLX.DAT filenames

 are specified in Input Group 0)

 Mass balance for each species

 reported hourly?

 (IMBAL) Default: 0 ! IMBAL = 0 !

 0 = no

 1 = yes (MASSBAL.DAT filename is

 specified in Input Group 0)

 LINE PRINTER OUTPUT OPTIONS:

 Print concentrations (ICPRT) Default: 0 ! ICPRT = 0 !

 Print dry fluxes (IDPRT) Default: 0 ! IDPRT = 0 !

 Print wet fluxes (IWPRT) Default: 0 ! IWPRT = 0 !

 (0 = Do not print, 1 = Print)

 Concentration print interval

 (ICFRQ) in hours Default: 1 ! ICFRQ = 1 !

 Dry flux print interval

 (IDFRQ) in hours Default: 1 ! IDFRQ = 1 !

 Wet flux print interval

 (IWFRQ) in hours Default: 1 ! IWFRQ = 1 !

 Units for Line Printer Output

 (IPRTU) Default: 1 ! IPRTU = 3 !

 for for

 Concentration Deposition

 1 = g/m**3 g/m**2/s

Page 9
p85prea.inp

 2 = mg/m**3 mg/m**2/s

 3 = ug/m**3 ug/m**2/s

 4 = ng/m**3 ng/m**2/s

 5 = Odour Units

 Messages tracking progress of run

 written to the screen ?

 (IMESG) Default: 2 ! IMESG = 2 !

 0 = no

 1 = yes (advection step, puff ID)

 2 = yes (YYYYJJJHH, # old puffs, # emitted puffs)

 SPECIES (or GROUP for combined species) LIST FOR OUTPUT OPTIONS

 ---- CONCENTRATIONS ---- ------ DRY FLUXES ------ ------ WET 

FLUXES ------ -- MASS FLUX --

 SPECIES

 /GROUP PRINTED? SAVED ON DISK? PRINTED? SAVED ON DISK? PRINTED? 

SAVED ON DISK? SAVED ON DISK?

 ------- ------------------------ ------------------------ 

------------------------ ---------------

! SO2 = 0, 1, 0, 1, 0, 

 1, 0 !

! SO4 = 0, 1, 0, 1, 0, 

 1, 0 !

! NOX = 0, 1, 0, 1, 0, 

 0, 0 !

! HNO3 = 0, 1, 0, 1, 0, 

 1, 0 !

! NO3 = 0, 1, 0, 1, 0, 

 1, 0 !

! PMC = 0, 1, 0, 1, 0, 

 1, 0 !

 OPTIONS FOR PRINTING "DEBUG" QUANTITIES (much output)

 Logical for debug output

 (LDEBUG) Default: F ! LDEBUG = F !

 First puff to track

 (IPFDEB) Default: 1 ! IPFDEB = 1 !

 Number of puffs to track

 (NPFDEB) Default: 1 ! NPFDEB = 1 !

 Met. period to start output

 (NN1) Default: 1 ! NN1 = 1 !

 Met. period to end output

 (NN2) Default: 10 ! NN2 = 10 !

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 6a, 6b, & 6c -- Subgrid scale complex terrain inputs

-------------------------

---------------

Page 10
p85prea.inp

Subgroup (6a)

---------------

 Number of terrain features (NHILL) Default: 0 ! NHILL = 0 !

 Number of special complex terrain

 receptors (NCTREC) Default: 0 ! NCTREC = 0 !

 Terrain and CTSG Receptor data for

 CTSG hills input in CTDM format ?

 (MHILL) No Default ! MHILL = 2 !

 1 = Hill and Receptor data created

 by CTDM processors & read from

 HILL.DAT and HILLRCT.DAT files

 2 = Hill data created by OPTHILL &

 input below in Subgroup (6b);

 Receptor data in Subgroup (6c)

 Factor to convert horizontal dimensions Default: 1.0 ! XHILL2M = 0. !

 to meters (MHILL=1)

 Factor to convert vertical dimensions Default: 1.0 ! ZHILL2M = 0. !

 to meters (MHILL=1)

 X-origin of CTDM system relative to No Default ! XCTDMKM = 0.0E00 !

 CALPUFF coordinate system, in Kilometers (MHILL=1)

 Y-origin of CTDM system relative to No Default ! YCTDMKM = 0.0E00 !

 CALPUFF coordinate system, in Kilometers (MHILL=1)

! END !

---------------

Subgroup (6b)

---------------

 1 **

 HILL information

HILL XC YC THETAH ZGRID RELIEF EXPO 1 EXPO 2 SCALE 

1 SCALE 2 AMAX1 AMAX2

 NO. (km) (km) (deg.) (m) (m) (m) (m) (m) 

 (m) (m) (m)

---- ---- ---- ------ ----- ------ ------ ------ 

------- ------- ----- -----

---------------

Subgroup (6c)

---------------

 COMPLEX TERRAIN RECEPTOR INFORMATION

 XRCT YRCT ZRCT XHH

 (km) (km) (m)

 ------ ----- ------ ----

-------------------

1

 Description of Complex Terrain Variables:

 XC, YC = Coordinates of center of hill

 THETAH = Orientation of major axis of hill (clockwise from

 North)

Page 11
p85prea.inp

 ZGRID = Height of the 0 of the grid above mean sea

 level

 RELIEF = Height of the crest of the hill above the grid elevation

 EXPO 1 = Hill-shape exponent for the major axis

 EXPO 2 = Hill-shape exponent for the major axis

 SCALE 1 = Horizontal length scale along the major axis

 SCALE 2 = Horizontal length scale along the minor axis

 AMAX = Maximum allowed axis length for the major axis

 BMAX = Maximum allowed axis length for the major axis

 XRCT, YRCT = Coordinates of the complex terrain receptors

 ZRCT = Height of the ground (MSL) at the complex terrain

 Receptor

 XHH = Hill number associated with each complex terrain receptor

 (NOTE: MUST BE ENTERED AS A REAL NUMBER)

 **

 NOTE: DATA for each hill and CTSG receptor are treated as a separate

 input subgroup and therefore must end with an input group terminator.

-------------------------------------------------------------------------------

INPUT GROUP: 7 -- Chemical parameters for dry deposition of gases

--------------

 SPECIES DIFFUSIVITY ALPHA STAR REACTIVITY MESOPHYLL 

RESISTANCE HENRY'S LAW COEFFICIENT

 NAME (cm**2/s) (s/cm) 

 (dimensionless)

 ------- ----------- ---------- ---------- 

-------------------- -----------------------

! SO2 = 0.1509, 1000., 8., 0., 

 0.04 !

! NOX = 0.1656, 1., 8., 5., 

 3.5 !

! HNO3 = 0.1628, 1., 180., 0., 

 0.00000008 !

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 8 -- Size parameters for dry deposition of particles

--------------

 For SINGLE SPECIES, the mean and standard deviation are used to

 compute a deposition velocity for NINT (see group 9) size-ranges,

 and these are then averaged to obtain a mean deposition velocity.

 For GROUPED SPECIES, the size distribution should be explicitly

 specified (by the 'species' in the group), and the standard deviation

 for each should be entered as 0. The model will then use the

 deposition velocity for the stated mean diameter.

 SPECIES GEOMETRIC MASS MEAN GEOMETRIC STANDARD

 NAME DIAMETER DEVIATION

 (microns) (microns)

 ------- ------------------- ------------------

! SO4 = 0.48, 2. !

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p85prea.inp

! NO3 = 0.48, 2. !

! PMC = 6.2, 0. !

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 9 -- Miscellaneous dry deposition parameters

--------------

 Reference cuticle resistance (s/cm)

 (RCUTR) Default: 30 ! RCUTR = 30.0 !

 Reference ground resistance (s/cm)

 (RGR) Default: 10 ! RGR = 10.0 !

 Reference pollutant reactivity

 (REACTR) Default: 8 ! REACTR = 8.0 !

 Number of particle-size intervals used to

 evaluate effective particle deposition velocity

 (NINT) Default: 9 ! NINT = 9 !

 Vegetation state in unirrigated areas

 (IVEG) Default: 1 ! IVEG = 1 !

 IVEG=1 for active and unstressed vegetation

 IVEG=2 for active and stressed vegetation

 IVEG=3 for inactive vegetation

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 10 -- Wet Deposition Parameters

---------------

 Scavenging Coefficient -- Units: (sec)**(-1)

 Pollutant Liquid Precip. Frozen Precip.

 --------- -------------- --------------

! SO2 = 3.0E-05, 0.0E00 !

! SO4 = 1.0E-04, 3.0E-05 !

! HNO3 = 6.0E-05, 0.0E00 !

! NO3 = 1.0E-04, 3.0E-05 !

! PMC = 1.0E-04, 3.0E-05 !

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 11 -- Chemistry Parameters

---------------

 Ozone data input option (MOZ) Default: 1 ! MOZ = 0 !

 (Used only if MCHEM = 1, 3, or 4)

 0 = use a constant background ozone value

 1 = read hourly ozone concentrations from

 the OZONE.DAT data file

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 Background ozone concentration

 (BCKO3) in ppb Default: 80. ! BCKO3 = 40.0 !

 (Used only if MCHEM = 1, 3, or 4 and

 MOZ = 0 or (MOZ = 1 and all hourly

 O3 data missing)

 Background ammonia concentration

 (BCKNH3) in ppb Default: 10. ! BCKNH3 = 1.0 !

 Nighttime SO2 loss rate (RNITE1)

 in percent/hour Default: 0.2 ! RNITE1 = .2 !

 Nighttime NOx loss rate (RNITE2)

 in percent/hour Default: 2.0 ! RNITE2 = 2.0 !

 Nighttime HNO3 formation rate (RNITE3)

 in percent/hour Default: 2.0 ! RNITE3 = 2.0 !

 --- Data for SECONDARY ORGANIC AEROSOL (SOA) Option

 (used only if MCHEM = 4)

 The SOA module uses monthly values of:

 Fine particulate concentration in ug/m^3 (BCKPMF)

 Organic fraction of fine particulate (OFRAC)

 VOC / NOX ratio (after reaction) (VCNX)

 to characterize the air mass when computing

 the formation of SOA from VOC emissions.

 Typical values for several distinct air mass types are:

 Month 1 2 3 4 5 6 7 8 9 10 11 12

 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

 Clean Continental

 BCKPMF 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. 1.

 OFRAC .15 .15 .20 .20 .20 .20 .20 .20 .20 .20 .20 .15

 VCNX 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50.

 Clean Marine (surface)

 BCKPMF .5 .5 .5 .5 .5 .5 .5 .5 .5 .5 .5 .5

 OFRAC .25 .25 .30 .30 .30 .30 .30 .30 .30 .30 .30 .25

 VCNX 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50.

 Urban - low biogenic (controls present)

 BCKPMF 30. 30. 30. 30. 30. 30. 30. 30. 30. 30. 30. 30.

 OFRAC .20 .20 .25 .25 .25 .25 .25 .25 .20 .20 .20 .20

 VCNX 4. 4. 4. 4. 4. 4. 4. 4. 4. 4. 4. 4.

 Urban - high biogenic (controls present)

 BCKPMF 60. 60. 60. 60. 60. 60. 60. 60. 60. 60. 60. 60.

 OFRAC .25 .25 .30 .30 .30 .55 .55 .55 .35 .35 .35 .25

 VCNX 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15.

 Regional Plume

 BCKPMF 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. 20.

 OFRAC .20 .20 .25 .35 .25 .40 .40 .40 .30 .30 .30 .20

 VCNX 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15.

 Urban - no controls present

 BCKPMF 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. 100.

 OFRAC .30 .30 .35 .35 .35 .55 .55 .55 .35 .35 .35 .30

 VCNX 2. 2. 2. 2. 2. 2. 2. 2. 2. 2. 2. 2.

Page 14
p85prea.inp

 Default: Clean Continental

 ! BCKPMF = 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 

1.00 !

 ! OFRAC = 0.15, 0.15, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 

0.15 !

 ! VCNX = 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 

50.00, 50.00, 50.00 !

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 12 -- Misc. Dispersion and Computational Parameters

---------------

 Horizontal size of puff (m) beyond which

 time-dependent dispersion equations (Heffter)

 are used to determine sigma-y and

 sigma-z (SYTDEP) Default: 550. ! SYTDEP = 5.5E02 !

 Switch for using Heffter equation for sigma z

 as above (0 = Not use Heffter; 1 = use Heffter

 (MHFTSZ) Default: 0 ! MHFTSZ = 0 !

 Stability class used to determine plume

 growth rates for puffs above the boundary

 layer (JSUP) Default: 5 ! JSUP = 5 !

 Vertical dispersion constant for stable

 conditions (k1 in Eqn. 2.7-3) (CONK1) Default: 0.01 ! CONK1 = .01 !

 Vertical dispersion constant for neutral/

 unstable conditions (k2 in Eqn. 2.7-4)

 (CONK2) Default: 0.1 ! CONK2 = .1 !

 Factor for determining Transition-point from

 Schulman-Scire to Huber-Snyder Building Downwash

 scheme (SS used for Hs < Hb + TBD * HL)

 (TBD) Default: 0.5 ! TBD = .5 !

 TBD < 0 ==> always use Huber-Snyder

 TBD = 1.5 ==> always use Schulman-Scire

 TBD = 0.5 ==> ISC Transition-point

 Range of land use categories for which

 urban dispersion is assumed

 (IURB1, IURB2) Default: 10 ! IURB1 = 10 !

 19 ! IURB2 = 19 !

 Site characterization parameters for single-point Met data files ---------

 (needed for METFM = 2,3,4)

 Land use category for modeling domain

 (ILANDUIN) Default: 20 ! ILANDUIN = 20 !

 Roughness length (m) for modeling domain

 (Z0IN) Default: 0.25 ! Z0IN = .25 !

 Leaf area index for modeling domain

 (XLAIIN) Default: 3.0 ! XLAIIN = 3.0 !

Page 15
p85prea.inp

 Elevation above sea level (m)

 (ELEVIN) Default: 0.0 ! ELEVIN = .0 !

 Latitude (degrees) for met location

 (XLATIN) Default: -999. ! XLATIN = 47.25 !

 Longitude (degrees) for met location

 (XLONIN) Default: -999. ! XLONIN = 91.25 !

 Specialized information for interpreting single-point Met data files -----

 Anemometer height (m) (Used only if METFM = 2,3)

 (ANEMHT) Default: 10. ! ANEMHT = 10.0 !

 Form of lateral turbulance data in PROFILE.DAT file

 (Used only if METFM = 4 or MTURBVW = 1 or 3)

 (ISIGMAV) Default: 1 ! ISIGMAV = 1 !

 0 = read sigma-theta

 1 = read sigma-v

 Choice of mixing heights (Used only if METFM = 4)

 (IMIXCTDM) Default: 0 ! IMIXCTDM = 0 !

 0 = read PREDICTED mixing heights

 1 = read OBSERVED mixing heights

 Maximum length of a slug (met. grid units)

 (XMXLEN) Default: 1.0 ! XMXLEN = 1.0 !

 Maximum travel distance of a puff/slug (in

 grid units) during one sampling step

 (XSAMLEN) Default: 1.0 ! XSAMLEN = 1.0 !

 Maximum Number of slugs/puffs release from

 one source during one time step

 (MXNEW) Default: 99 ! MXNEW = 99 !

 Maximum Number of sampling steps for

 one puff/slug during one time step

 (MXSAM) Default: 99 ! MXSAM = 99 !

 Number of iterations used when computing

 the transport wind for a sampling step

 that includes gradual rise (for CALMET

 and PROFILE winds)

 (NCOUNT) Default: 2 ! NCOUNT = 2 !

 Minimum sigma y for a new puff/slug (m)

 (SYMIN) Default: 1.0 ! SYMIN = 1.0 !

 Minimum sigma z for a new puff/slug (m)

 (SZMIN) Default: 1.0 ! SZMIN = 1.0 !

 Default minimum turbulence velocities

 sigma-v and sigma-w for each

 stability class (m/s)

 (SVMIN(6) and SWMIN(6)) Default SVMIN : .50, .50, .50, .50, .50, .50

 Default SWMIN : .20, .12, .08, .06, .03, .016

 Stability Class : A B C D E F

 --- --- --- --- --- ---

 ! SVMIN = 0.500, 0.500, 0.500, 0.500, 0.500, 

0.500!

 ! SWMIN = 0.200, 0.120, 0.080, 0.060, 0.030, 

Page 16
p85prea.inp

0.016!

 Divergence criterion for dw/dz across puff

 used to initiate adjustment for horizontal

 convergence (1/s)

 Partial adjustment starts at CDIV(1), and

 full adjustment is reached at CDIV(2)

 (CDIV(2)) Default: 0.0,0.0 ! CDIV = .01, .01 

!

 Minimum wind speed (m/s) allowed for

 non-calm conditions. Also used as minimum

 speed returned when using power-law

 extrapolation toward surface

 (WSCALM) Default: 0.5 ! WSCALM = .5 !

 Maximum mixing height (m)

 (XMAXZI) Default: 3000. ! XMAXZI = 3000.0 !

 Minimum mixing height (m)

 (XMINZI) Default: 50. ! XMINZI = 50.0 !

 Default wind speed classes --

 5 upper bounds (m/s) are entered;

 the 6th class has no upper limit

 (WSCAT(5)) Default :

 ISC RURAL : 1.54, 3.09, 5.14, 8.23, 10,8 

(10.8+)

 Wind Speed Class : 1 2 3 4 5 6

 --- --- --- --- --- ---

 ! WSCAT = 9.95, 10.49, 11.52, 12.04, 14.35 !

 Default wind speed profile power-law

 exponents for stabilities 1-6

 (PLX0(6)) Default : ISC RURAL values

 ISC RURAL : .07, .07, .10, .15, .35, .55

 ISC URBAN : .15, .15, .20, .25, .30, .30

 Stability Class : A B C D E F

 --- --- --- --- --- ---

 ! PLX0 = 0.07, 0.07, 0.10, 0.15, 0.35, 0.55 

!

 Default potential temperature gradient

 for stable classes E, F (degK/m)

 (PTG0(2)) Default: 0.020, 0.035

 ! PTG0 = 0.020, 0.035 !

 Default plume path coefficients for

 each stability class (used when option

 for partial plume height terrain adjustment

 is selected -- MCTADJ=3)

 (PPC(6)) Stability Class : A B C D E F

 Default PPC : .50, .50, .50, .50, .35, .35

 --- --- --- --- --- ---

 ! PPC = 0.50, 0.50, 0.50, 0.50, 0.35, 0.35 

!

 Slug-to-puff transition criterion factor

 equal to sigma-y/length of slug

 (SL2PF) Default: 10. ! SL2PF = 10.0 !

Page 17
p85prea.inp

 Puff-splitting control variables ------------------------

 VERTICAL SPLIT

 --------------

 Number of puffs that result every time a puff

 is split - nsplit=2 means that 1 puff splits

 into 2

 (NSPLIT) Default: 3 ! NSPLIT = 3 !

 Time(s) of a day when split puffs are eligible to

 be split once again; this is typically set once

 per day, around sunset before nocturnal shear develops.

 24 values: 0 is midnight (00:00) and 23 is 11 PM (23:00)

 0=do not re-split 1=eligible for re-split

 (IRESPLIT(24)) Default: Hour 17 = 1

 ! IRESPLIT = 0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,1,0,0,0,0,0,0 !

 Split is allowed only if last hour's mixing

 height (m) exceeds a minimum value

 (ZISPLIT) Default: 100. ! ZISPLIT = 100.0 !

 Split is allowed only if ratio of last hour's

 mixing ht to the maximum mixing ht experienced

 by the puff is less than a maximum value (this

 postpones a split until a nocturnal layer develops)

 (ROLDMAX) Default: 0.25 ! ROLDMAX = 0.25 !

 HORIZONTAL SPLIT

 ----------------

 Number of puffs that result every time a puff

 is split - nsplith=5 means that 1 puff splits

 into 5

 (NSPLITH) Default: 5 ! NSPLITH = 5 !

 Minimum sigma-y (Grid Cells Units) of puff

 before it may be split

 (SYSPLITH) Default: 1.0 ! SYSPLITH = 1.0 !

 Minimum puff elongation rate (SYSPLITH/hr) due to

 wind shear, before it may be split

 (SHSPLITH) Default: 2. ! SHSPLITH = 2.0 !

 Minimum concentration (g/m^3) of each

 species in puff before it may be split

 Enter array of NSPEC values; if a single value is

 entered, it will be used for ALL species

 (CNSPLITH) Default: 1.0E-07 ! CNSPLITH = 1.0E-07 

!

 Integration control variables ------------------------

 Fractional convergence criterion for numerical SLUG

 sampling integration

 (EPSSLUG) Default: 1.0e-04 ! EPSSLUG = 1.0E-04 !

 Fractional convergence criterion for numerical AREA

 source integration

 (EPSAREA) Default: 1.0e-06 ! EPSAREA = 1.0E-06 !

 Trajectory step-length (m) used for numerical rise

Page 18
p85prea.inp

 integration

 (DSRISE) Default: 1.0 ! DSRISE = 1.0 !

!END!

-------------------------------------------------------------------------------

INPUT GROUPS: 13a, 13b, 13c, 13d -- Point source parameters

--------------------------------

---------------

Subgroup (13a)

---------------

 Number of point sources with

 parameters provided below (NPT1) No default ! NPT1 = 4 !

 Units used for point source

 emissions below (IPTU) Default: 1 ! IPTU = 4 !

 1 = g/s

 2 = kg/hr

 3 = lb/hr

 4 = tons/yr

 5 = Odour Unit * m**3/s (vol. flux of odour compound)

 6 = Odour Unit * m**3/min

 7 = metric tons/yr

 Number of source-species

 combinations with variable

 emissions scaling factors

 provided below in (13d) (NSPT1) Default: 0 ! NSPT1 = 0 !

 Number of point sources with

 variable emission parameters

 provided in external file (NPT2) No default ! NPT2 = 0 !

 (If NPT2 > 0, these point

 source emissions are read from

 the file: PTEMARB.DAT)

!END!

---------------

Subgroup (13b)

---------------

 a

 POINT SOURCE: CONSTANT DATA

 -----------------------------

 b 

 c

 Source X UTM Y UTM Stack Base Stack Exit Exit Bldg. 

Emission

 No. Coordinate Coordinate Height Elevation Diameter Vel. Temp. Dwash 

Rates

 (km) (km) (m) (m) (m) (m/s) (deg. K)

 ------ ---------- ---------- ------ ------ -------- ----- -------- ----- 

--------

 1 ! SRCNAM = GK01 !

 1 ! X = 519.154, 5260.181, 42.7, 475.0, 2.4, 19.0, 330.0, 0.0, 

6693.0E00, 0.0E00,

 21395.0E00, 0.0E00, 0.0E00, 4595.0E00 !

Page 19
p85prea.inp

 1 ! FMFAC = 1.0 ! !END!

 2 ! SRCNAM = SG01 !

 2 ! X = 519.154, 5260.181, 42.7, 475.0, 4.0, 14.0, 330.0, 0.0, 

331.0E00, 0.0E00,

 4396.0E00, 0.0E00, 0.0E00, 358.0E00 !

 2 ! FMFAC = 1.0 ! !END!

 3 ! SRCNAM = PC01 !

 3 ! X = 519.154, 5260.181, 41.1, 475.0, 4.0, 9.0, 700.0, 0.0, 0.0E00,

 0.0E00, 0.0E00,

 0.0E00, 0.0E00, 195.0E00 !

 3 ! FMFAC = 1.0 ! !END!

 4 ! SRCNAM = OH01 !

 4 ! X = 519.154, 5260.181, 24.4, 475.0, .61, 12.0, 298.0, 0.0, 0.0E00,

 0.0E00, 0.0E00,

 0.0E00, 0.0E00, 1027.0E00 !

 4 ! FMFAC = 1.0 ! !END!

--------

 a

 Data for each source are treated as a separate input subgroup

 and therefore must end with an input group terminator.

 SRCNAM is a 12-character name for a source

 (No default)

 X is an array holding the source data listed by the column headings

 (No default)

 SIGYZI is an array holding the initial sigma-y and sigma-z (m)

 (Default: 0.,0.)

 FMFAC is a vertical momentum flux factor (0. or 1.0) used to represent

 the effect of rain-caps or other physical configurations that

 reduce momentum rise associated with the actual exit velocity.

 (Default: 1.0 -- full momentum used)

 b

 0. = No building downwash modeled, 1. = downwash modeled

 NOTE: must be entered as a REAL number (i.e., with decimal point)

 c

 An emission rate must be entered for every pollutant modeled.

 Enter emission rate of zero for secondary pollutants that are

 modeled, but not emitted. Units are specified by IPTU

 (e.g. 1 for g/s).

---------------

Subgroup (13c)

---------------

 BUILDING DIMENSION DATA FOR SOURCES SUBJECT TO DOWNWASH

 -------------------------------------------------------

Source a

 No. Effective building width and height (in meters) every 10 degrees

------ ----------------------------------------------------------------

 *END*

--------

 a

 Each pair of width and height values is treated as a separate input

 subgroup and therefore must end with an input group terminator.

Page 20
p85prea.inp

---------------

Subgroup (13d)

---------------

 a

 POINT SOURCE: VARIABLE EMISSIONS DATA

 ---------------------------------------

 Use this subgroup to describe temporal variations in the emission

 rates given in 13b. Factors entered multiply the rates in 13b.

 Skip sources here that have constant emissions. For more elaborate

 variation in source parameters, use PTEMARB.DAT and NPT2 > 0.

 IVARY determines the type of variation, and is source-specific:

 (IVARY) Default: 0

 0 = Constant

 1 = Diurnal cycle (24 scaling factors: hours 1-24)

 2 = Monthly cycle (12 scaling factors: months 1-12)

 3 = Hour & Season (4 groups of 24 hourly scaling factors,

 where first group is DEC-JAN-FEB)

 4 = Speed & Stab. (6 groups of 6 scaling factors, where

 first group is Stability Class A,

 and the speed classes have upper

 bounds (m/s) defined in Group 12

 5 = Temperature (12 scaling factors, where temperature

 classes have upper bounds (C) of:

 0, 5, 10, 15, 20, 25, 30, 35, 40,

 45, 50, 50+)

--------

 a

 Data for each species are treated as a separate input subgroup

 and therefore must end with an input group terminator.

-------------------------------------------------------------------------------

INPUT GROUPS: 14a, 14b, 14c, 14d -- Area source parameters

--------------------------------

---------------

Subgroup (14a)

---------------

 Number of polygon area sources with

 parameters specified below (NAR1) No default ! NAR1 = 0 !

 Units used for area source

 emissions below (IARU) Default: 1 ! IARU = 1 !

 1 = g/m**2/s

 2 = kg/m**2/hr

 3 = lb/m**2/hr

 4 = tons/m**2/yr

 5 = Odour Unit * m/s (vol. flux/m**2 of odour compound)

 6 = Odour Unit * m/min

 7 = metric tons/m**2/yr

 Number of source-species

 combinations with variable

 emissions scaling factors

 provided below in (14d) (NSAR1) Default: 0 ! NSAR1 = 0 !

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 Number of buoyant polygon area sources

 with variable location and emission

 parameters (NAR2) No default ! NAR2 = 0 !

 (If NAR2 > 0, ALL parameter data for

 these sources are read from the file: BAEMARB.DAT)

!END!

---------------

Subgroup (14b)

---------------

 a

 AREA SOURCE: CONSTANT DATA

 ----------------------------

 b

Source Effect. Base Initial Emission

 No. Height Elevation Sigma z Rates

 (m) (m) (m)

------- ------ ------ -------- ---------

--------

 a

 Data for each source are treated as a separate input subgroup

 and therefore must end with an input group terminator.

 b

 An emission rate must be entered for every pollutant modeled.

 Enter emission rate of zero for secondary pollutants that are

 modeled, but not emitted. Units are specified by IARU

 (e.g. 1 for g/m**2/s).

---------------

Subgroup (14c)

---------------

 COORDINATES (UTM-km) FOR EACH VERTEX(4) OF EACH POLYGON

 --------------------------------------------------------

Source a

 No. Ordered list of X followed by list of Y, grouped by source

------ ------------------------------------------------------------

--------

 a

 Data for each source are treated as a separate input subgroup

 and therefore must end with an input group terminator.

---------------

Subgroup (14d)

---------------

 a

 AREA SOURCE: VARIABLE EMISSIONS DATA

 --------------------------------------

 Use this subgroup to describe temporal variations in the emission

 rates given in 14b. Factors entered multiply the rates in 14b.

 Skip sources here that have constant emissions. For more elaborate

 variation in source parameters, use BAEMARB.DAT and NAR2 > 0.

 IVARY determines the type of variation, and is source-specific:

 (IVARY) Default: 0

Page 22
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 0 = Constant

 1 = Diurnal cycle (24 scaling factors: hours 1-24)

 2 = Monthly cycle (12 scaling factors: months 1-12)

 3 = Hour & Season (4 groups of 24 hourly scaling factors,

 where first group is DEC-JAN-FEB)

 4 = Speed & Stab. (6 groups of 6 scaling factors, where

 first group is Stability Class A,

 and the speed classes have upper

 bounds (m/s) defined in Group 12

 5 = Temperature (12 scaling factors, where temperature

 classes have upper bounds (C) of:

 0, 5, 10, 15, 20, 25, 30, 35, 40,

 45, 50, 50+)

--------

 a

 Data for each species are treated as a separate input subgroup

 and therefore must end with an input group terminator.

-------------------------------------------------------------------------------

INPUT GROUPS: 15a, 15b, 15c -- Line source parameters

---------------------------

---------------

Subgroup (15a)

---------------

 Number of buoyant line sources

 with variable location and emission

 parameters (NLN2) No default ! NLN2 = 0 !

 (If NLN2 > 0, ALL parameter data for

 these sources are read from the file: LNEMARB.DAT)

 Number of buoyant line sources (NLINES) No default ! NLINES = 0 !

 Units used for line source

 emissions below (ILNU) Default: 1 ! ILNU = 1 !

 1 = g/s

 2 = kg/hr

 3 = lb/hr

 4 = tons/yr

 5 = Odour Unit * m**3/s (vol. flux of odour compound)

 6 = Odour Unit * m**3/min

 7 = metric tons/yr

 Number of source-species

 combinations with variable

 emissions scaling factors

 provided below in (15c) (NSLN1) Default: 0 ! NSLN1 = 0 !

 Maximum number of segments used to model

 each line (MXNSEG) Default: 7 ! MXNSEG = 7 !

 The following variables are required only if NLINES > 0. They are

 used in the buoyant line source plume rise calculations.

 Number of distances at which Default: 6 ! NLRISE = 6 !

 transitional rise is computed

Page 23
p85prea.inp

 Average building length (XL) No default ! XL = .0 !

 (in meters)

 Average building height (HBL) No default ! HBL = .0 !

 (in meters)

 Average building width (WBL) No default ! WBL = .0 !

 (in meters)

 Average line source width (WML) No default ! WML = .0 !

 (in meters)

 Average separation between buildings (DXL) No default ! DXL = .0 !

 (in meters)

 Average buoyancy parameter (FPRIMEL) No default ! FPRIMEL = .0 !

 (in m**4/s**3)

!END!

---------------

Subgroup (15b)

---------------

 BUOYANT LINE SOURCE: CONSTANT DATA

 ----------------------------------

 

 a

Source Beg. X Beg. Y End. X End. Y Release Base 

Emission

 No. Coordinate Coordinate Coordinate Coordinate Height Elevation 

Rates

 (km) (km) (km) (km) (m) (m)

------ ---------- ---------- --------- ---------- ------- --------- 

---------

--------

 a

 Data for each source are treated as a separate input subgroup

 and therefore must end with an input group terminator.

 b

 An emission rate must be entered for every pollutant modeled.

 Enter emission rate of zero for secondary pollutants that are

 modeled, but not emitted. Units are specified by ILNTU

 (e.g. 1 for g/s).

---------------

Subgroup (15c)

---------------

 a

 BUOYANT LINE SOURCE: VARIABLE EMISSIONS DATA

 ----------------------------------------------

 Use this subgroup to describe temporal variations in the emission

 rates given in 15b. Factors entered multiply the rates in 15b.

 Skip sources here that have constant emissions.

 IVARY determines the type of variation, and is source-specific:

 (IVARY) Default: 0

 0 = Constant

Page 24
p85prea.inp

 1 = Diurnal cycle (24 scaling factors: hours 1-24)

 2 = Monthly cycle (12 scaling factors: months 1-12)

 3 = Hour & Season (4 groups of 24 hourly scaling factors,

 where first group is DEC-JAN-FEB)

 4 = Speed & Stab. (6 groups of 6 scaling factors, where

 first group is Stability Class A,

 and the speed classes have upper

 bounds (m/s) defined in Group 12

 5 = Temperature (12 scaling factors, where temperature

 classes have upper bounds (C) of:

 0, 5, 10, 15, 20, 25, 30, 35, 40,

 45, 50, 50+)

--------

 a

 Data for each species are treated as a separate input subgroup

 and therefore must end with an input group terminator.

-------------------------------------------------------------------------------

INPUT GROUPS: 16a, 16b, 16c -- Volume source parameters

---------------------------

---------------

Subgroup (16a)

---------------

 Number of volume sources with

 parameters provided in 16b,c (NVL1) No default ! NVL1 = 0 !

 Units used for volume source

 emissions below in 16b (IVLU) Default: 1 ! IVLU = 1 !

 1 = g/s

 2 = kg/hr

 3 = lb/hr

 4 = tons/yr

 5 = Odour Unit * m**3/s (vol. flux of odour compound)

 6 = Odour Unit * m**3/min

 7 = metric tons/yr

 Number of source-species

 combinations with variable

 emissions scaling factors

 provided below in (16c) (NSVL1) Default: 0 ! NSVL1 = 0 !

 Number of volume sources with

 variable location and emission

 parameters (NVL2) No default ! NVL2 = 0 !

 (If NVL2 > 0, ALL parameter data for

 these sources are read from the VOLEMARB.DAT file(s) )

!END!

---------------

Subgroup (16b)

---------------

 a

 VOLUME SOURCE: CONSTANT DATA

Page 25
p85prea.inp

 ------------------------------

 b

 X UTM Y UTM Effect. Base Initial Initial Emission

 Coordinate Coordinate Height Elevation Sigma y Sigma z Rates

 (km) (km) (m) (m) (m) (m)

 ---------- ---------- ------ ------ -------- -------- --------

--------

 a

 Data for each source are treated as a separate input subgroup

 and therefore must end with an input group terminator.

 b

 An emission rate must be entered for every pollutant modeled.

 Enter emission rate of zero for secondary pollutants that are

 modeled, but not emitted. Units are specified by IVLU

 (e.g. 1 for g/s).

---------------

Subgroup (16c)

---------------

 a

 VOLUME SOURCE: VARIABLE EMISSIONS DATA

 ----------------------------------------

 Use this subgroup to describe temporal variations in the emission

 rates given in 16b. Factors entered multiply the rates in 16b.

 Skip sources here that have constant emissions. For more elaborate

 variation in source parameters, use VOLEMARB.DAT and NVL2 > 0.

 IVARY determines the type of variation, and is source-specific:

 (IVARY) Default: 0

 0 = Constant

 1 = Diurnal cycle (24 scaling factors: hours 1-24)

 2 = Monthly cycle (12 scaling factors: months 1-12)

 3 = Hour & Season (4 groups of 24 hourly scaling factors,

 where first group is DEC-JAN-FEB)

 4 = Speed & Stab. (6 groups of 6 scaling factors, where

 first group is Stability Class A,

 and the speed classes have upper

 bounds (m/s) defined in Group 12

 5 = Temperature (12 scaling factors, where temperature

 classes have upper bounds (C) of:

 0, 5, 10, 15, 20, 25, 30, 35, 40,

 45, 50, 50+)

--------

 a

 Data for each species are treated as a separate input subgroup

 and therefore must end with an input group terminator.

-------------------------------------------------------------------------------

INPUT GROUPS: 17a & 17b -- Non-gridded (discrete) receptor information

-----------------------

---------------

Subgroup (17a)

---------------

Page 26
p85prea.inp

 Number of non-gridded receptors (NREC) No default ! NREC = 500 !

!END!

---------------

Subgroup (17b)

---------------

 a

 NON-GRIDDED (DISCRETE) RECEPTOR DATA

 ------------------------------------

 X UTM Y UTM Ground Height b

Receptor Coordinate Coordinate Elevation Above Ground

 No. (km) (km) (m) (m)

-------- ---------- ---------- --------- ------------

 1 ! X = 610.77, 5292.41, 472.000, 0.000! !END!

 2 ! X = 612.77, 5292.41, 473.000, 0.000! !END!

 3 ! X = 614.77, 5292.41, 473.900, 0.000! !END!

 4 ! X = 618.77, 5292.41, 471.200, 0.000! !END!

 5 ! X = 620.77, 5292.41, 474.800, 0.000! !END!

 6 ! X = 606.77, 5294.41, 458.400, 0.000! !END!

 7 ! X = 608.77, 5294.41, 470.900, 0.000! !END!

 8 ! X = 610.77, 5294.41, 459.700, 0.000! !END!

 9 ! X = 612.77, 5294.41, 474.800, 0.000! !END!

 10 ! X = 614.77, 5294.41, 468.000, 0.000! !END!

 11 ! X = 616.77, 5294.41, 469.300, 0.000! !END!

 12 ! X = 618.77, 5294.41, 463.400, 0.000! !END!

 13 ! X = 620.77, 5294.41, 472.000, 0.000! !END!

 14 ! X = 622.77, 5294.41, 487.000, 0.000! !END!

 15 ! X = 624.77, 5294.41, 468.700, 0.000! !END!

 16 ! X = 630.77, 5294.41, 491.600, 0.000! !END!

 17 ! X = 632.77, 5294.41, 493.800, 0.000! !END!

 18 ! X = 634.77, 5294.41, 503.000, 0.000! !END!

 19 ! X = 636.77, 5294.41, 511.100, 0.000! !END!

 20 ! X = 638.77, 5294.41, 502.000, 0.000! !END!

 21 ! X = 604.77, 5296.41, 500.900, 0.000! !END!

 22 ! X = 606.77, 5296.41, 460.600, 0.000! !END!

 23 ! X = 608.77, 5296.41, 449.100, 0.000! !END!

 24 ! X = 610.77, 5296.41, 464.900, 0.000! !END!

 25 ! X = 612.77, 5296.41, 472.000, 0.000! !END!

 26 ! X = 614.77, 5296.41, 457.000, 0.000! !END!

 27 ! X = 616.77, 5296.41, 466.400, 0.000! !END!

 28 ! X = 618.77, 5296.41, 457.000, 0.000! !END!

 29 ! X = 620.77, 5296.41, 466.700, 0.000! !END!

 30 ! X = 622.77, 5296.41, 482.000, 0.000! !END!

 31 ! X = 624.77, 5296.41, 472.000, 0.000! !END!

 32 ! X = 626.77, 5296.41, 478.000, 0.000! !END!

 33 ! X = 628.77, 5296.41, 478.000, 0.000! !END!

 34 ! X = 630.77, 5296.41, 487.000, 0.000! !END!

 35 ! X = 632.77, 5296.41, 487.100, 0.000! !END!

 36 ! X = 634.77, 5296.41, 502.000, 0.000! !END!

 37 ! X = 636.77, 5296.41, 502.000, 0.000! !END!

 38 ! X = 638.77, 5296.41, 500.700, 0.000! !END!

 39 ! X = 604.77, 5298.41, 463.600, 0.000! !END!

 40 ! X = 606.77, 5298.41, 467.000, 0.000! !END!

 41 ! X = 608.77, 5298.41, 441.000, 0.000! !END!

 42 ! X = 610.77, 5298.41, 469.400, 0.000! !END!

 43 ! X = 612.77, 5298.41, 472.000, 0.000! !END!

 44 ! X = 614.77, 5298.41, 472.000, 0.000! !END!

 45 ! X = 616.77, 5298.41, 472.000, 0.000! !END!

 46 ! X = 618.77, 5298.41, 472.000, 0.000! !END!

 47 ! X = 620.77, 5298.41, 472.000, 0.000! !END!

Page 27
p85prea.inp

 48 ! X = 622.77, 5298.41, 472.000, 0.000! !END!

 49 ! X = 624.77, 5298.41, 476.600, 0.000! !END!

 50 ! X = 626.77, 5298.41, 485.000, 0.000! !END!

 51 ! X = 628.77, 5298.41, 486.500, 0.000! !END!

 52 ! X = 630.77, 5298.41, 487.000, 0.000! !END!

 53 ! X = 632.77, 5298.41, 500.000, 0.000! !END!

 54 ! X = 634.77, 5298.41, 502.000, 0.000! !END!

 55 ! X = 636.77, 5298.41, 517.500, 0.000! !END!

 56 ! X = 638.77, 5298.41, 518.000, 0.000! !END!

 57 ! X = 602.77, 5300.41, 450.900, 0.000! !END!

 58 ! X = 604.77, 5300.41, 441.000, 0.000! !END!

 59 ! X = 606.77, 5300.41, 442.300, 0.000! !END!

 60 ! X = 608.77, 5300.41, 462.300, 0.000! !END!

 61 ! X = 610.77, 5300.41, 462.300, 0.000! !END!

 62 ! X = 612.77, 5300.41, 463.000, 0.000! !END!

 63 ! X = 614.77, 5300.41, 479.300, 0.000! !END!

 64 ! X = 616.77, 5300.41, 474.400, 0.000! !END!

 65 ! X = 618.77, 5300.41, 483.100, 0.000! !END!

 66 ! X = 620.77, 5300.41, 481.100, 0.000! !END!

 67 ! X = 622.77, 5300.41, 487.000, 0.000! !END!

 68 ! X = 624.77, 5300.41, 487.000, 0.000! !END!

 69 ! X = 626.77, 5300.41, 504.500, 0.000! !END!

 70 ! X = 628.77, 5300.41, 490.700, 0.000! !END!

 71 ! X = 630.77, 5300.41, 505.900, 0.000! !END!

 72 ! X = 632.77, 5300.41, 514.200, 0.000! !END!

 73 ! X = 634.77, 5300.41, 512.400, 0.000! !END!

 74 ! X = 636.77, 5300.41, 517.300, 0.000! !END!

 75 ! X = 638.77, 5300.41, 519.400, 0.000! !END!

 76 ! X = 640.77, 5300.41, 516.500, 0.000! !END!

 77 ! X = 642.77, 5300.41, 518.300, 0.000! !END!

 78 ! X = 644.77, 5300.41, 539.600, 0.000! !END!

 79 ! X = 646.77, 5300.41, 549.000, 0.000! !END!

 80 ! X = 648.77, 5300.41, 544.600, 0.000! !END!

 81 ! X = 650.77, 5300.41, 588.700, 0.000! !END!

 82 ! X = 652.77, 5300.41, 572.800, 0.000! !END!

 83 ! X = 654.77, 5300.41, 562.200, 0.000! !END!

 84 ! X = 656.77, 5300.41, 590.000, 0.000! !END!

 85 ! X = 600.77, 5302.41, 435.000, 0.000! !END!

 86 ! X = 602.77, 5302.41, 438.400, 0.000! !END!

 87 ! X = 604.77, 5302.41, 458.000, 0.000! !END!

 88 ! X = 606.77, 5302.41, 453.400, 0.000! !END!

 89 ! X = 608.77, 5302.41, 471.000, 0.000! !END!

 90 ! X = 610.77, 5302.41, 472.000, 0.000! !END!

 91 ! X = 612.77, 5302.41, 474.800, 0.000! !END!

 92 ! X = 614.77, 5302.41, 498.300, 0.000! !END!

 93 ! X = 616.77, 5302.41, 481.800, 0.000! !END!

 94 ! X = 618.77, 5302.41, 472.000, 0.000! !END!

 95 ! X = 620.77, 5302.41, 468.000, 0.000! !END!

 96 ! X = 622.77, 5302.41, 472.000, 0.000! !END!

 97 ! X = 624.77, 5302.41, 472.000, 0.000! !END!

 98 ! X = 626.77, 5302.41, 489.900, 0.000! !END!

 99 ! X = 628.77, 5302.41, 487.000, 0.000! !END!

 100 ! X = 630.77, 5302.41, 507.300, 0.000! !END!

 101 ! X = 632.77, 5302.41, 518.000, 0.000! !END!

 102 ! X = 634.77, 5302.41, 547.900, 0.000! !END!

 103 ! X = 636.77, 5302.41, 517.200, 0.000! !END!

 104 ! X = 638.77, 5302.41, 528.500, 0.000! !END!

 105 ! X = 640.77, 5302.41, 517.400, 0.000! !END!

 106 ! X = 642.77, 5302.41, 520.400, 0.000! !END!

 107 ! X = 644.77, 5302.41, 532.700, 0.000! !END!

 108 ! X = 646.77, 5302.41, 576.300, 0.000! !END!

 109 ! X = 648.77, 5302.41, 542.000, 0.000! !END!

 110 ! X = 650.77, 5302.41, 558.300, 0.000! !END!

Page 28
p85prea.inp

 111 ! X = 652.77, 5302.41, 589.600, 0.000! !END!

 112 ! X = 654.77, 5302.41, 578.600, 0.000! !END!

 113 ! X = 656.77, 5302.41, 573.200, 0.000! !END!

 114 ! X = 662.77, 5302.41, 531.500, 0.000! !END!

 115 ! X = 664.77, 5302.41, 548.000, 0.000! !END!

 116 ! X = 666.77, 5302.41, 563.000, 0.000! !END!

 117 ! X = 668.77, 5302.41, 548.800, 0.000! !END!

 118 ! X = 598.77, 5304.41, 451.000, 0.000! !END!

 119 ! X = 600.77, 5304.41, 454.200, 0.000! !END!

 120 ! X = 602.77, 5304.41, 438.000, 0.000! !END!

 121 ! X = 604.77, 5304.41, 449.100, 0.000! !END!

 122 ! X = 606.77, 5304.41, 461.800, 0.000! !END!

 123 ! X = 608.77, 5304.41, 469.000, 0.000! !END!

 124 ! X = 610.77, 5304.41, 470.000, 0.000! !END!

 125 ! X = 612.77, 5304.41, 463.300, 0.000! !END!

 126 ! X = 614.77, 5304.41, 457.000, 0.000! !END!

 127 ! X = 616.77, 5304.41, 451.000, 0.000! !END!

 128 ! X = 618.77, 5304.41, 457.000, 0.000! !END!

 129 ! X = 620.77, 5304.41, 456.300, 0.000! !END!

 130 ! X = 622.77, 5304.41, 472.000, 0.000! !END!

 131 ! X = 624.77, 5304.41, 472.000, 0.000! !END!

 132 ! X = 626.77, 5304.41, 473.000, 0.000! !END!

 133 ! X = 628.77, 5304.41, 487.000, 0.000! !END!

 134 ! X = 630.77, 5304.41, 476.900, 0.000! !END!

 135 ! X = 632.77, 5304.41, 487.000, 0.000! !END!

 136 ! X = 634.77, 5304.41, 488.500, 0.000! !END!

 137 ! X = 636.77, 5304.41, 517.000, 0.000! !END!

 138 ! X = 638.77, 5304.41, 521.000, 0.000! !END!

 139 ! X = 640.77, 5304.41, 503.800, 0.000! !END!

 140 ! X = 642.77, 5304.41, 521.400, 0.000! !END!

 141 ! X = 644.77, 5304.41, 533.000, 0.000! !END!

 142 ! X = 646.77, 5304.41, 548.000, 0.000! !END!

 143 ! X = 648.77, 5304.41, 542.600, 0.000! !END!

 144 ! X = 650.77, 5304.41, 576.000, 0.000! !END!

 145 ! X = 652.77, 5304.41, 554.000, 0.000! !END!

 146 ! X = 654.77, 5304.41, 583.400, 0.000! !END!

 147 ! X = 656.77, 5304.41, 557.000, 0.000! !END!

 148 ! X = 660.77, 5304.41, 562.000, 0.000! !END!

 149 ! X = 662.77, 5304.41, 575.500, 0.000! !END!

 150 ! X = 664.77, 5304.41, 576.100, 0.000! !END!

 151 ! X = 666.77, 5304.41, 568.400, 0.000! !END!

 152 ! X = 668.77, 5304.41, 619.300, 0.000! !END!

 153 ! X = 670.77, 5304.41, 586.000, 0.000! !END!

 154 ! X = 554.77, 5306.41, 426.000, 0.000! !END!

 155 ! X = 556.77, 5306.41, 440.400, 0.000! !END!

 156 ! X = 558.77, 5306.41, 442.800, 0.000! !END!

 157 ! X = 560.77, 5306.41, 448.800, 0.000! !END!

 158 ! X = 562.77, 5306.41, 471.300, 0.000! !END!

 159 ! X = 564.77, 5306.41, 481.200, 0.000! !END!

 160 ! X = 566.77, 5306.41, 476.500, 0.000! !END!

 161 ! X = 568.77, 5306.41, 442.000, 0.000! !END!

 162 ! X = 570.77, 5306.41, 429.100, 0.000! !END!

 163 ! X = 596.77, 5306.41, 420.200, 0.000! !END!

 164 ! X = 598.77, 5306.41, 435.200, 0.000! !END!

 165 ! X = 600.77, 5306.41, 451.200, 0.000! !END!

 166 ! X = 602.77, 5306.41, 438.000, 0.000! !END!

 167 ! X = 604.77, 5306.41, 462.000, 0.000! !END!

 168 ! X = 606.77, 5306.41, 445.000, 0.000! !END!

 169 ! X = 608.77, 5306.41, 473.000, 0.000! !END!

 170 ! X = 610.77, 5306.41, 471.600, 0.000! !END!

 171 ! X = 612.77, 5306.41, 472.000, 0.000! !END!

 172 ! X = 614.77, 5306.41, 453.400, 0.000! !END!

 173 ! X = 616.77, 5306.41, 451.000, 0.000! !END!

Page 29
p85prea.inp

 174 ! X = 618.77, 5306.41, 451.000, 0.000! !END!

 175 ! X = 620.77, 5306.41, 454.000, 0.000! !END!

 176 ! X = 622.77, 5306.41, 454.000, 0.000! !END!

 177 ! X = 624.77, 5306.41, 465.500, 0.000! !END!

 178 ! X = 626.77, 5306.41, 472.000, 0.000! !END!

 179 ! X = 628.77, 5306.41, 470.400, 0.000! !END!

 180 ! X = 630.77, 5306.41, 472.000, 0.000! !END!

 181 ! X = 632.77, 5306.41, 488.500, 0.000! !END!

 182 ! X = 634.77, 5306.41, 498.600, 0.000! !END!

 183 ! X = 636.77, 5306.41, 525.300, 0.000! !END!

 184 ! X = 638.77, 5306.41, 518.600, 0.000! !END!

 185 ! X = 640.77, 5306.41, 502.000, 0.000! !END!

 186 ! X = 642.77, 5306.41, 502.000, 0.000! !END!

 187 ! X = 644.77, 5306.41, 521.400, 0.000! !END!

 188 ! X = 646.77, 5306.41, 562.100, 0.000! !END!

 189 ! X = 648.77, 5306.41, 569.300, 0.000! !END!

 190 ! X = 650.77, 5306.41, 605.000, 0.000! !END!

 191 ! X = 652.77, 5306.41, 579.200, 0.000! !END!

 192 ! X = 654.77, 5306.41, 563.000, 0.000! !END!

 193 ! X = 656.77, 5306.41, 559.300, 0.000! !END!

 194 ! X = 658.77, 5306.41, 553.900, 0.000! !END!

 195 ! X = 660.77, 5306.41, 548.000, 0.000! !END!

 196 ! X = 662.77, 5306.41, 548.000, 0.000! !END!

 197 ! X = 664.77, 5306.41, 530.700, 0.000! !END!

 198 ! X = 666.77, 5306.41, 563.900, 0.000! !END!

 199 ! X = 668.77, 5306.41, 562.600, 0.000! !END!

 200 ! X = 670.77, 5306.41, 563.000, 0.000! !END!

 201 ! X = 672.77, 5306.41, 562.500, 0.000! !END!

 202 ! X = 680.77, 5306.41, 563.000, 0.000! !END!

 203 ! X = 682.77, 5306.41, 556.700, 0.000! !END!

 204 ! X = 548.77, 5308.41, 454.000, 0.000! !END!

 205 ! X = 550.77, 5308.41, 428.600, 0.000! !END!

 206 ! X = 552.77, 5308.41, 441.400, 0.000! !END!

 207 ! X = 554.77, 5308.41, 453.600, 0.000! !END!

 208 ! X = 556.77, 5308.41, 442.000, 0.000! !END!

 209 ! X = 558.77, 5308.41, 456.600, 0.000! !END!

 210 ! X = 560.77, 5308.41, 461.300, 0.000! !END!

 211 ! X = 562.77, 5308.41, 485.300, 0.000! !END!

 212 ! X = 564.77, 5308.41, 472.000, 0.000! !END!

 213 ! X = 566.77, 5308.41, 466.100, 0.000! !END!

 214 ! X = 568.77, 5308.41, 457.000, 0.000! !END!

 215 ! X = 570.77, 5308.41, 443.300, 0.000! !END!

 216 ! X = 604.77, 5308.41, 451.600, 0.000! !END!

 217 ! X = 606.77, 5308.41, 470.300, 0.000! !END!

 218 ! X = 608.77, 5308.41, 448.500, 0.000! !END!

 219 ! X = 610.77, 5308.41, 457.000, 0.000! !END!

 220 ! X = 612.77, 5308.41, 451.000, 0.000! !END!

 221 ! X = 614.77, 5308.41, 457.000, 0.000! !END!

 222 ! X = 616.77, 5308.41, 456.000, 0.000! !END!

 223 ! X = 618.77, 5308.41, 457.000, 0.000! !END!

 224 ! X = 620.77, 5308.41, 458.500, 0.000! !END!

 225 ! X = 622.77, 5308.41, 461.300, 0.000! !END!

 226 ! X = 624.77, 5308.41, 479.200, 0.000! !END!

 227 ! X = 626.77, 5308.41, 461.000, 0.000! !END!

 228 ! X = 628.77, 5308.41, 460.000, 0.000! !END!

 229 ! X = 630.77, 5308.41, 472.600, 0.000! !END!

 230 ! X = 632.77, 5308.41, 484.100, 0.000! !END!

 231 ! X = 634.77, 5308.41, 483.800, 0.000! !END!

 232 ! X = 636.77, 5308.41, 530.600, 0.000! !END!

 233 ! X = 638.77, 5308.41, 499.200, 0.000! !END!

 234 ! X = 640.77, 5308.41, 503.000, 0.000! !END!

 235 ! X = 642.77, 5308.41, 505.400, 0.000! !END!

 236 ! X = 644.77, 5308.41, 532.200, 0.000! !END!

Page 30
p85prea.inp

 237 ! X = 646.77, 5308.41, 533.000, 0.000! !END!

 238 ! X = 648.77, 5308.41, 576.800, 0.000! !END!

 239 ! X = 650.77, 5308.41, 591.900, 0.000! !END!

 240 ! X = 652.77, 5308.41, 593.000, 0.000! !END!

 241 ! X = 654.77, 5308.41, 594.400, 0.000! !END!

 242 ! X = 656.77, 5308.41, 561.100, 0.000! !END!

 243 ! X = 658.77, 5308.41, 548.000, 0.000! !END!

 244 ! X = 660.77, 5308.41, 563.000, 0.000! !END!

 245 ! X = 662.77, 5308.41, 594.000, 0.000! !END!

 246 ! X = 664.77, 5308.41, 539.400, 0.000! !END!

 247 ! X = 666.77, 5308.41, 563.000, 0.000! !END!

 248 ! X = 668.77, 5308.41, 566.000, 0.000! !END!

 249 ! X = 670.77, 5308.41, 566.600, 0.000! !END!

 250 ! X = 680.77, 5308.41, 573.500, 0.000! !END!

 251 ! X = 682.77, 5308.41, 595.900, 0.000! !END!

 252 ! X = 546.77, 5310.41, 457.000, 0.000! !END!

 253 ! X = 548.77, 5310.41, 438.300, 0.000! !END!

 254 ! X = 550.77, 5310.41, 427.000, 0.000! !END!

 255 ! X = 552.77, 5310.41, 427.000, 0.000! !END!

 256 ! X = 554.77, 5310.41, 442.200, 0.000! !END!

 257 ! X = 556.77, 5310.41, 470.000, 0.000! !END!

 258 ! X = 558.77, 5310.41, 472.000, 0.000! !END!

 259 ! X = 560.77, 5310.41, 456.800, 0.000! !END!

 260 ! X = 562.77, 5310.41, 472.000, 0.000! !END!

 261 ! X = 564.77, 5310.41, 486.700, 0.000! !END!

 262 ! X = 566.77, 5310.41, 479.500, 0.000! !END!

 263 ! X = 568.77, 5310.41, 472.000, 0.000! !END!

 264 ! X = 570.77, 5310.41, 445.000, 0.000! !END!

 265 ! X = 620.77, 5310.41, 471.100, 0.000! !END!

 266 ! X = 622.77, 5310.41, 472.000, 0.000! !END!

 267 ! X = 624.77, 5310.41, 486.900, 0.000! !END!

 268 ! X = 626.77, 5310.41, 484.800, 0.000! !END!

 269 ! X = 628.77, 5310.41, 471.200, 0.000! !END!

 270 ! X = 630.77, 5310.41, 471.000, 0.000! !END!

 271 ! X = 632.77, 5310.41, 484.000, 0.000! !END!

 272 ! X = 634.77, 5310.41, 486.600, 0.000! !END!

 273 ! X = 636.77, 5310.41, 514.900, 0.000! !END!

 274 ! X = 638.77, 5310.41, 488.400, 0.000! !END!

 275 ! X = 640.77, 5310.41, 488.900, 0.000! !END!

 276 ! X = 642.77, 5310.41, 487.000, 0.000! !END!

 277 ! X = 644.77, 5310.41, 517.200, 0.000! !END!

 278 ! X = 646.77, 5310.41, 532.800, 0.000! !END!

 279 ! X = 648.77, 5310.41, 562.500, 0.000! !END!

 280 ! X = 650.77, 5310.41, 593.000, 0.000! !END!

 281 ! X = 652.77, 5310.41, 609.000, 0.000! !END!

 282 ! X = 654.77, 5310.41, 609.000, 0.000! !END!

 283 ! X = 656.77, 5310.41, 563.000, 0.000! !END!

 284 ! X = 658.77, 5310.41, 563.000, 0.000! !END!

 285 ! X = 660.77, 5310.41, 563.000, 0.000! !END!

 286 ! X = 662.77, 5310.41, 574.000, 0.000! !END!

 287 ! X = 664.77, 5310.41, 563.000, 0.000! !END!

 288 ! X = 666.77, 5310.41, 578.000, 0.000! !END!

 289 ! X = 668.77, 5310.41, 578.400, 0.000! !END!

 290 ! X = 670.77, 5310.41, 593.700, 0.000! !END!

 291 ! X = 672.77, 5310.41, 561.200, 0.000! !END!

 292 ! X = 676.77, 5310.41, 565.000, 0.000! !END!

 293 ! X = 678.77, 5310.41, 624.000, 0.000! !END!

 294 ! X = 680.77, 5310.41, 610.500, 0.000! !END!

 295 ! X = 682.77, 5310.41, 595.100, 0.000! !END!

 296 ! X = 684.77, 5310.41, 595.400, 0.000! !END!

 297 ! X = 686.77, 5310.41, 603.900, 0.000! !END!

 298 ! X = 688.77, 5310.41, 608.000, 0.000! !END!

 299 ! X = 546.77, 5312.41, 435.900, 0.000! !END!

Page 31
p85prea.inp

 300 ! X = 548.77, 5312.41, 455.000, 0.000! !END!

 301 ! X = 550.77, 5312.41, 427.000, 0.000! !END!

 302 ! X = 552.77, 5312.41, 427.000, 0.000! !END!

 303 ! X = 554.77, 5312.41, 457.000, 0.000! !END!

 304 ! X = 556.77, 5312.41, 467.400, 0.000! !END!

 305 ! X = 558.77, 5312.41, 472.000, 0.000! !END!

 306 ! X = 560.77, 5312.41, 457.000, 0.000! !END!

 307 ! X = 562.77, 5312.41, 482.300, 0.000! !END!

 308 ! X = 564.77, 5312.41, 472.000, 0.000! !END!

 309 ! X = 566.77, 5312.41, 465.300, 0.000! !END!

 310 ! X = 568.77, 5312.41, 457.000, 0.000! !END!

 311 ! X = 570.77, 5312.41, 467.200, 0.000! !END!

 312 ! X = 572.77, 5312.41, 458.400, 0.000! !END!

 313 ! X = 594.77, 5312.41, 408.700, 0.000! !END!

 314 ! X = 596.77, 5312.41, 410.100, 0.000! !END!

 315 ! X = 598.77, 5312.41, 411.000, 0.000! !END!

 316 ! X = 600.77, 5312.41, 456.700, 0.000! !END!

 317 ! X = 620.77, 5312.41, 486.500, 0.000! !END!

 318 ! X = 622.77, 5312.41, 469.000, 0.000! !END!

 319 ! X = 624.77, 5312.41, 492.100, 0.000! !END!

 320 ! X = 626.77, 5312.41, 484.600, 0.000! !END!

 321 ! X = 628.77, 5312.41, 472.000, 0.000! !END!

 322 ! X = 630.77, 5312.41, 473.200, 0.000! !END!

 323 ! X = 632.77, 5312.41, 484.000, 0.000! !END!

 324 ! X = 634.77, 5312.41, 489.400, 0.000! !END!

 325 ! X = 636.77, 5312.41, 485.500, 0.000! !END!

 326 ! X = 638.77, 5312.41, 487.000, 0.000! !END!

 327 ! X = 640.77, 5312.41, 484.000, 0.000! !END!

 328 ! X = 642.77, 5312.41, 487.000, 0.000! !END!

 329 ! X = 644.77, 5312.41, 497.500, 0.000! !END!

 330 ! X = 646.77, 5312.41, 508.100, 0.000! !END!

 331 ! X = 648.77, 5312.41, 562.300, 0.000! !END!

 332 ! X = 650.77, 5312.41, 563.100, 0.000! !END!

 333 ! X = 652.77, 5312.41, 594.000, 0.000! !END!

 334 ! X = 654.77, 5312.41, 569.000, 0.000! !END!

 335 ! X = 656.77, 5312.41, 581.200, 0.000! !END!

 336 ! X = 658.77, 5312.41, 579.000, 0.000! !END!

 337 ! X = 660.77, 5312.41, 574.500, 0.000! !END!

 338 ! X = 662.77, 5312.41, 548.000, 0.000! !END!

 339 ! X = 664.77, 5312.41, 563.000, 0.000! !END!

 340 ! X = 666.77, 5312.41, 579.000, 0.000! !END!

 341 ! X = 668.77, 5312.41, 560.000, 0.000! !END!

 342 ! X = 670.77, 5312.41, 560.000, 0.000! !END!

 343 ! X = 672.77, 5312.41, 560.000, 0.000! !END!

 344 ! X = 674.77, 5312.41, 560.000, 0.000! !END!

 345 ! X = 676.77, 5312.41, 560.000, 0.000! !END!

 346 ! X = 678.77, 5312.41, 578.100, 0.000! !END!

 347 ! X = 680.77, 5312.41, 548.000, 0.000! !END!

 348 ! X = 682.77, 5312.41, 567.600, 0.000! !END!

 349 ! X = 684.77, 5312.41, 597.600, 0.000! !END!

 350 ! X = 686.77, 5312.41, 554.100, 0.000! !END!

 351 ! X = 688.77, 5312.41, 515.000, 0.000! !END!

 352 ! X = 546.77, 5314.41, 442.000, 0.000! !END!

 353 ! X = 548.77, 5314.41, 457.800, 0.000! !END!

 354 ! X = 550.77, 5314.41, 427.000, 0.000! !END!

 355 ! X = 552.77, 5314.41, 444.800, 0.000! !END!

 356 ! X = 554.77, 5314.41, 454.700, 0.000! !END!

 357 ! X = 556.77, 5314.41, 460.200, 0.000! !END!

 358 ! X = 558.77, 5314.41, 437.000, 0.000! !END!

 359 ! X = 560.77, 5314.41, 451.100, 0.000! !END!

 360 ! X = 562.77, 5314.41, 446.200, 0.000! !END!

 361 ! X = 564.77, 5314.41, 472.000, 0.000! !END!

 362 ! X = 566.77, 5314.41, 464.800, 0.000! !END!

Page 32
p85prea.inp

 363 ! X = 568.77, 5314.41, 445.000, 0.000! !END!

 364 ! X = 570.77, 5314.41, 449.500, 0.000! !END!

 365 ! X = 572.77, 5314.41, 461.200, 0.000! !END!

 366 ! X = 594.77, 5314.41, 402.000, 0.000! !END!

 367 ! X = 596.77, 5314.41, 426.000, 0.000! !END!

 368 ! X = 598.77, 5314.41, 408.000, 0.000! !END!

 369 ! X = 600.77, 5314.41, 436.700, 0.000! !END!

 370 ! X = 602.77, 5314.41, 436.800, 0.000! !END!

 371 ! X = 604.77, 5314.41, 423.000, 0.000! !END!

 372 ! X = 620.77, 5314.41, 441.000, 0.000! !END!

 373 ! X = 622.77, 5314.41, 446.800, 0.000! !END!

 374 ! X = 624.77, 5314.41, 472.000, 0.000! !END!

 375 ! X = 626.77, 5314.41, 487.000, 0.000! !END!

 376 ! X = 628.77, 5314.41, 476.400, 0.000! !END!

 377 ! X = 630.77, 5314.41, 484.200, 0.000! !END!

 378 ! X = 632.77, 5314.41, 484.100, 0.000! !END!

 379 ! X = 634.77, 5314.41, 501.900, 0.000! !END!

 380 ! X = 636.77, 5314.41, 486.500, 0.000! !END!

 381 ! X = 638.77, 5314.41, 487.000, 0.000! !END!

 382 ! X = 640.77, 5314.41, 486.900, 0.000! !END!

 383 ! X = 642.77, 5314.41, 491.900, 0.000! !END!

 384 ! X = 644.77, 5314.41, 502.000, 0.000! !END!

 385 ! X = 646.77, 5314.41, 527.900, 0.000! !END!

 386 ! X = 648.77, 5314.41, 573.300, 0.000! !END!

 387 ! X = 650.77, 5314.41, 558.000, 0.000! !END!

 388 ! X = 652.77, 5314.41, 552.900, 0.000! !END!

 389 ! X = 654.77, 5314.41, 563.000, 0.000! !END!

 390 ! X = 656.77, 5314.41, 550.100, 0.000! !END!

 391 ! X = 658.77, 5314.41, 553.400, 0.000! !END!

 392 ! X = 660.77, 5314.41, 587.400, 0.000! !END!

 393 ! X = 662.77, 5314.41, 579.000, 0.000! !END!

 394 ! X = 664.77, 5314.41, 536.000, 0.000! !END!

 395 ! X = 666.77, 5314.41, 626.000, 0.000! !END!

 396 ! X = 668.77, 5314.41, 607.200, 0.000! !END!

 397 ! X = 670.77, 5314.41, 598.600, 0.000! !END!

 398 ! X = 672.77, 5314.41, 563.000, 0.000! !END!

 399 ! X = 674.77, 5314.41, 623.300, 0.000! !END!

 400 ! X = 676.77, 5314.41, 620.000, 0.000! !END!

 401 ! X = 678.77, 5314.41, 623.500, 0.000! !END!

 402 ! X = 680.77, 5314.41, 588.100, 0.000! !END!

 403 ! X = 682.77, 5314.41, 579.500, 0.000! !END!

 404 ! X = 684.77, 5314.41, 531.900, 0.000! !END!

 405 ! X = 686.77, 5314.41, 544.700, 0.000! !END!

 406 ! X = 688.77, 5314.41, 580.800, 0.000! !END!

 407 ! X = 546.77, 5316.41, 442.600, 0.000! !END!

 408 ! X = 548.77, 5316.41, 456.000, 0.000! !END!

 409 ! X = 550.77, 5316.41, 427.000, 0.000! !END!

 410 ! X = 552.77, 5316.41, 443.500, 0.000! !END!

 411 ! X = 554.77, 5316.41, 444.800, 0.000! !END!

 412 ! X = 556.77, 5316.41, 457.000, 0.000! !END!

 413 ! X = 558.77, 5316.41, 440.500, 0.000! !END!

 414 ! X = 560.77, 5316.41, 448.900, 0.000! !END!

 415 ! X = 562.77, 5316.41, 448.300, 0.000! !END!

 416 ! X = 564.77, 5316.41, 445.000, 0.000! !END!

 417 ! X = 566.77, 5316.41, 445.000, 0.000! !END!

 418 ! X = 568.77, 5316.41, 445.000, 0.000! !END!

 419 ! X = 570.77, 5316.41, 458.100, 0.000! !END!

 420 ! X = 572.77, 5316.41, 457.000, 0.000! !END!

 421 ! X = 574.77, 5316.41, 493.600, 0.000! !END!

 422 ! X = 576.77, 5316.41, 456.700, 0.000! !END!

 423 ! X = 592.77, 5316.41, 426.000, 0.000! !END!

 424 ! X = 594.77, 5316.41, 414.100, 0.000! !END!

 425 ! X = 596.77, 5316.41, 420.400, 0.000! !END!

Page 33
p85prea.inp

 426 ! X = 598.77, 5316.41, 412.100, 0.000! !END!

 427 ! X = 600.77, 5316.41, 410.700, 0.000! !END!

 428 ! X = 602.77, 5316.41, 432.800, 0.000! !END!

 429 ! X = 604.77, 5316.41, 411.000, 0.000! !END!

 430 ! X = 606.77, 5316.41, 426.100, 0.000! !END!

 431 ! X = 608.77, 5316.41, 411.000, 0.000! !END!

 432 ! X = 610.77, 5316.41, 409.800, 0.000! !END!

 433 ! X = 618.77, 5316.41, 435.000, 0.000! !END!

 434 ! X = 620.77, 5316.41, 452.800, 0.000! !END!

 435 ! X = 622.77, 5316.41, 437.300, 0.000! !END!

 436 ! X = 624.77, 5316.41, 518.800, 0.000! !END!

 437 ! X = 626.77, 5316.41, 457.000, 0.000! !END!

 438 ! X = 628.77, 5316.41, 471.100, 0.000! !END!

 439 ! X = 630.77, 5316.41, 472.000, 0.000! !END!

 440 ! X = 632.77, 5316.41, 468.500, 0.000! !END!

 441 ! X = 634.77, 5316.41, 487.000, 0.000! !END!

 442 ! X = 636.77, 5316.41, 486.500, 0.000! !END!

 443 ! X = 638.77, 5316.41, 495.300, 0.000! !END!

 444 ! X = 640.77, 5316.41, 487.000, 0.000! !END!

 445 ! X = 642.77, 5316.41, 502.700, 0.000! !END!

 446 ! X = 644.77, 5316.41, 516.300, 0.000! !END!

 447 ! X = 646.77, 5316.41, 518.300, 0.000! !END!

 448 ! X = 648.77, 5316.41, 534.700, 0.000! !END!

 449 ! X = 650.77, 5316.41, 548.000, 0.000! !END!

 450 ! X = 652.77, 5316.41, 535.400, 0.000! !END!

 451 ! X = 654.77, 5316.41, 548.000, 0.000! !END!

 452 ! X = 656.77, 5316.41, 518.000, 0.000! !END!

 453 ! X = 658.77, 5316.41, 533.000, 0.000! !END!

 454 ! X = 660.77, 5316.41, 535.800, 0.000! !END!

 455 ! X = 662.77, 5316.41, 552.500, 0.000! !END!

 456 ! X = 664.77, 5316.41, 533.000, 0.000! !END!

 457 ! X = 666.77, 5316.41, 578.000, 0.000! !END!

 458 ! X = 668.77, 5316.41, 578.700, 0.000! !END!

 459 ! X = 670.77, 5316.41, 598.400, 0.000! !END!

 460 ! X = 672.77, 5316.41, 594.000, 0.000! !END!

 461 ! X = 674.77, 5316.41, 603.600, 0.000! !END!

 462 ! X = 676.77, 5316.41, 618.300, 0.000! !END!

 463 ! X = 678.77, 5316.41, 622.900, 0.000! !END!

 464 ! X = 680.77, 5316.41, 639.000, 0.000! !END!

 465 ! X = 682.77, 5316.41, 651.700, 0.000! !END!

 466 ! X = 684.77, 5316.41, 659.600, 0.000! !END!

 467 ! X = 686.77, 5316.41, 629.300, 0.000! !END!

 468 ! X = 688.77, 5316.41, 648.800, 0.000! !END!

 469 ! X = 546.77, 5318.41, 442.000, 0.000! !END!

 470 ! X = 548.77, 5318.41, 442.000, 0.000! !END!

 471 ! X = 550.77, 5318.41, 434.200, 0.000! !END!

 472 ! X = 552.77, 5318.41, 427.000, 0.000! !END!

 473 ! X = 554.77, 5318.41, 442.000, 0.000! !END!

 474 ! X = 556.77, 5318.41, 427.000, 0.000! !END!

 475 ! X = 558.77, 5318.41, 442.000, 0.000! !END!

 476 ! X = 560.77, 5318.41, 453.100, 0.000! !END!

 477 ! X = 562.77, 5318.41, 442.000, 0.000! !END!

 478 ! X = 564.77, 5318.41, 457.000, 0.000! !END!

 479 ! X = 566.77, 5318.41, 457.000, 0.000! !END!

 480 ! X = 568.77, 5318.41, 451.000, 0.000! !END!

 481 ! X = 570.77, 5318.41, 443.400, 0.000! !END!

 482 ! X = 572.77, 5318.41, 457.000, 0.000! !END!

 483 ! X = 574.77, 5318.41, 461.500, 0.000! !END!

 484 ! X = 576.77, 5318.41, 454.100, 0.000! !END!

 485 ! X = 592.77, 5318.41, 426.000, 0.000! !END!

 486 ! X = 594.77, 5318.41, 401.600, 0.000! !END!

 487 ! X = 596.77, 5318.41, 405.200, 0.000! !END!

 488 ! X = 598.77, 5318.41, 404.700, 0.000! !END!

Page 34
p85prea.inp

 489 ! X = 600.77, 5318.41, 414.900, 0.000! !END!

 490 ! X = 602.77, 5318.41, 396.000, 0.000! !END!

 491 ! X = 604.77, 5318.41, 411.000, 0.000! !END!

 492 ! X = 606.77, 5318.41, 426.500, 0.000! !END!

 493 ! X = 608.77, 5318.41, 436.500, 0.000! !END!

 494 ! X = 610.77, 5318.41, 425.000, 0.000! !END!

 495 ! X = 612.77, 5318.41, 420.200, 0.000! !END!

 496 ! X = 614.77, 5318.41, 445.300, 0.000! !END!

 497 ! X = 616.77, 5318.41, 456.300, 0.000! !END!

 498 ! X = 618.77, 5318.41, 436.700, 0.000! !END!

 499 ! X = 620.77, 5318.41, 444.700, 0.000! !END!

 500 ! X = 622.77, 5318.41, 470.600, 0.000! !END!

-------------

 a

 Data for each receptor are treated as a separate input subgroup

 and therefore must end with an input group terminator.

 b

 Receptor height above ground is optional. If no value is entered,

 the receptor is placed on the ground.

Page 35
ATTACHMENT V 

CALPOST Input File (One of Six Files) 
VISPREA.inp

MPCA Taconite BART Study - Pre-BART Emissions 

Boundary Waters C. A. Wilderness (1-500)

CALMET data - 12/1/84 through 11/30/85 

---------------- Run title (3 lines) ------------------------------------------

 CALPOST MODEL CONTROL FILE

 --------------------------

-------------------------------------------------------------------------------

INPUT GROUP: 0 -- Input and Output File Names

--------------

Input Files

-----------

File Default File Name

---- -----------------

Conc/Dep Flux File MODEL.DAT ! MODDAT 

=L:\CALPUFF\BART\OUTPUT\P85PREA.CON !

Relative Humidity File VISB.DAT ! VISDAT 

=L:\CALPUFF\BART\OUTPUT\P85PREA.VIS !

Background Data File BACK.DAT *BACKDAT = *

Transmissometer/ VSRN.DAT *VSRDAT = *

Nephelometer Data File

Output Files

------------

File Default File Name

---- -----------------

List File CALPOST.LST ! PSTLST 

=L:\CALPOST\BART\OUTPUT\VISPREA.LST !

Pathname for Timeseries Files (blank) * TSPATH = *

(activate with exclamation points only if

providing NON-BLANK character string)

Pathname for Plot Files (blank) ! PLPATH =L:\CALPOST\BART\OUTPUT\ !

(activate with exclamation points only if

 providing NON-BLANK character string)

User Character String (U) to augment default filenames

(activate with exclamation points only if

 providing NON-BLANK character string)

Timeseries TSttUUUU.DAT * TSUNAM = *

Top Nth Rank Plot RttUUUUU.DAT

 or RttiiUUU.GRD * TUNAM = *

Exceedance Plot XttUUUUU.DAT

 or XttUUUUU.GRD * XUNAM = *

Echo Plot jjjtthhU.DAT

(Specific Days) or jjjtthhU.GRD * EUNAM = *

Visibility Plot V24UUUUU.DAT ! VUNAM =PREA !

(Daily Peak Summary) 

--------------------------------------------------------------------------------

All file names will be converted to lower case if LCFILES = T

Otherwise, if LCFILES = F, file names will be converted to UPPER CASE

Page 1
VISPREA.inp

 T = lower case ! LCFILES = F !

 F = UPPER CASE

NOTE: (1) file/path names can be up to 70 characters in length

NOTE: (2) Filenames for ALL PLOT and TIMESERIES FILES are constructed

 using a template that includes a pathname, user-supplied 

 character(s), and fixed strings (tt,ii,jjj, and hh), where

 tt = Averaging Period (e.g. 03)

 ii = Rank (e.g. 02)

 jjj= Julian Day

 hh = Hour(ending)

 are determined internally based on selections made below.

 If a path or user-supplied character(s) are supplied, each

 must contain at least 1 non-blank character.

!END!

--------------------------------------------------------------------------------

INPUT GROUP: 1 -- General run control parameters

--------------

 Option to run all periods found

 in the met. file(s) (METRUN) Default: 0 ! METRUN = 1 !

 METRUN = 0 - Run period explicitly defined below

 METRUN = 1 - Run all periods in CALPUFF data file(s)

 Starting date: Year (ISYR) -- No default ! ISYR = 1984 !

 (used only if Month (ISMO) -- No default ! ISMO = 0 !

 METRUN = 0) Day (ISDY) -- No default ! ISDY = 0 !

 Hour (ISHR) -- No default ! ISHR = 0 !

 Number of hours to process (NHRS) -- No default ! NHRS = 0 !

 Process every hour of data?(NREP) -- Default: 1 ! NREP = 1 !

 (1 = every hour processed,

 2 = every 2nd hour processed,

 5 = every 5th hour processed, etc.)

Species & Concentration/Deposition Information

----------------------------------------------

 Species to process (ASPEC) -- No default ! ASPEC = VISIB !

 (ASPEC = VISIB for visibility processing)

 Layer/deposition code (ILAYER) -- Default: 1 ! ILAYER = 1 !

 '1' for CALPUFF concentrations,

 '-1' for dry deposition fluxes,

 '-2' for wet deposition fluxes,

 '-3' for wet+dry deposition fluxes.

 Scaling factors of the form: -- Defaults: ! A = 0.0 !

 X(new) = X(old) * A + B A = 0.0 ! B = 0.0 !

 (NOT applied if A = B = 0.0) B = 0.0

 Add Hourly Background Concentrations/Fluxes?

 (LBACK) -- Default: F ! LBACK = F !

Receptor information

--------------------

 Gridded receptors processed? (LG) -- Default: F ! LG = F !

 Discrete receptors processed? (LD) -- Default: F ! LD = T !

 CTSG Complex terrain receptors processed?

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 (LCT) -- Default: F ! LCT = F !

--Report results by DISCRETE receptor RING?

 (only used when LD = T) (LDRING) -- Default: F ! LDRING = F !

--Select range of DISCRETE receptors (only used when LD = T):

 Select ALL DISCRETE receptors by setting NDRECP flag to -1;

 OR

 Select SPECIFIC DISCRETE receptors by entering a flag (0,1) for each

 0 = discrete receptor not processed

 1 = discrete receptor processed

 using repeated value notation to select blocks of receptors:

 23*1, 15*0, 12*1

 Flag for all receptors after the last one assigned is set to 0

 (NDRECP) -- Default: -1

 ! NDRECP = -1 !

--Select range of GRIDDED receptors (only used when LG = T):

 X index of LL corner (IBGRID) -- Default: -1 ! IBGRID = -1 !

 (-1 OR 1 <= IBGRID <= NX)

 Y index of LL corner (JBGRID) -- Default: -1 ! JBGRID = -1 !

 (-1 OR 1 <= JBGRID <= NY)

 X index of UR corner (IEGRID) -- Default: -1 ! IEGRID = -1 !

 (-1 OR 1 <= IEGRID <= NX)

 Y index of UR corner (JEGRID) -- Default: -1 ! JEGRID = -1 !

 (-1 OR 1 <= JEGRID <= NY)

 Note: Entire grid is processed if IBGRID=JBGRID=IEGRID=JEGRID=-1

--Specific gridded receptors can also be excluded from CALPOST

 processing by filling a processing grid array with 0s and 1s. If the

 processing flag for receptor index (i,j) is 1 (ON), that receptor

 will be processed if it lies within the range delineated by IBGRID,

 JBGRID,IEGRID,JEGRID and if LG=T. If it is 0 (OFF), it will not be

 processed in the run. By default, all array values are set to 1 (ON).

 Number of gridded receptor rows provided in Subgroup (1a) to

 identify specific gridded receptors to process

 (NGONOFF) -- Default: 0 ! NGONOFF = 0 !

!END!

--------------

Subgroup (1a) -- Specific gridded receptors included/excluded

--------------

 Specific gridded receptors are excluded from CALPOST processing

 by filling a processing grid array with 0s and 1s. A total of

 NGONOFF lines are read here. Each line corresponds to one 'row'

 in the sampling grid, starting with the NORTHERNMOST row that

 contains receptors that you wish to exclude, and finishing with

 row 1 to the SOUTH (no intervening rows may be skipped). Within

 a row, each receptor position is assigned either a 0 or 1,

 starting with the westernmost receptor.

 0 = gridded receptor not processed

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 1 = gridded receptor processed

 Repeated value notation may be used to select blocks of receptors:

 23*1, 15*0, 12*1

 Because all values are initially set to 1, any receptors north of

 the first row entered, or east of the last value provided in a row,

 remain ON.

 (NGXRECP) -- Default: 1

-------------------------------------------------------------------------------

INPUT GROUP: 2 -- Visibility Parameters (ASPEC = VISIB)

--------------

 Maximum relative humidity (%) used in particle growth curve

 (RHMAX) -- Default: 98 ! RHMAX = 95.0 !

 Modeled species to be included in computing the light extinction

 Include SULFATE? (LVSO4) -- Default: T ! LVSO4 = T !

 Include NITRATE? (LVNO3) -- Default: T ! LVNO3 = T !

 Include ORGANIC CARBON? (LVOC) -- Default: T ! LVOC = F !

 Include COARSE PARTICLES? (LVPMC) -- Default: T ! LVPMC = T !

 Include FINE PARTICLES? (LVPMF) -- Default: T ! LVPMF = F !

 Include ELEMENTAL CARBON? (LVEC) -- Default: T ! LVEC = F !

 And, when ranking for TOP-N, TOP-50, and Exceedance tables,

 Include BACKGROUND? (LVBK) -- Default: T ! LVBK = F !

 Species name used for particulates in MODEL.DAT file

 COARSE (SPECPMC) -- Default: PMC ! SPECPMC = PMC !

 FINE (SPECPMF) -- Default: PMF ! SPECPMF = PMF !

Extinction Efficiency (1/Mm per ug/m**3)

----------------------------------------

 MODELED particulate species:

 PM COARSE (EEPMC) -- Default: 0.6 ! EEPMC = 0.6 !

 PM FINE (EEPMF) -- Default: 1.0 ! EEPMF = 1.0 !

 BACKGROUND particulate species:

 PM COARSE (EEPMCBK) -- Default: 0.6 ! EEPMCBK = 0.6 !

 Other species:

 AMMONIUM SULFATE (EESO4) -- Default: 3.0 ! EESO4 = 3.0 !

 AMMONIUM NITRATE (EENO3) -- Default: 3.0 ! EENO3 = 3.0 !

 ORGANIC CARBON (EEOC) -- Default: 4.0 ! EEOC = 4.0 !

 SOIL (EESOIL)-- Default: 1.0 ! EESOIL = 1.0 !

 ELEMENTAL CARBON (EEEC) -- Default: 10. ! EEEC = 10.0 !

Background Extinction Computation

---------------------------------

 Method used for background light extinction

 (MVISBK) -- Default: 6 ! MVISBK = 2 !

 1 = Supply single light extinction and hygroscopic fraction

 - IWAQM (1993) RH adjustment applied to hygroscopic background

 and modeled sulfate and nitrate

 2 = Compute extinction from speciated PM measurements (A)

 - Hourly RH adjustment applied to observed and modeled sulfate

 and nitrate

 - RH factor is capped at RHMAX

 3 = Compute extinction from speciated PM measurements (B)

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 - Hourly RH adjustment applied to observed and modeled sulfate

 and nitrate

 - Receptor-hour excluded if RH>RHMAX

 - Receptor-day excluded if fewer than 6 valid receptor-hours

 4 = Read hourly transmissometer background extinction measurements

 - Hourly RH adjustment applied to modeled sulfate and nitrate

 - Hour excluded if measurement invalid (missing, interference,

 or large RH)

 - Receptor-hour excluded if RH>RHMAX

 - Receptor-day excluded if fewer than 6 valid receptor-hours

 5 = Read hourly nephelometer background extinction measurements

 - Rayleigh extinction value (BEXTRAY) added to measurement

 - Hourly RH adjustment applied to modeled sulfate and nitrate

 - Hour excluded if measurement invalid (missing, interference,

 or large RH)

 - Receptor-hour excluded if RH>RHMAX

 - Receptor-day excluded if fewer than 6 valid receptor-hours

 6 = Compute extinction from speciated PM measurements

 - FLAG RH adjustment factor applied to observed and

 modeled sulfate and nitrate

 Additional inputs used for MVISBK = 1:

 --------------------------------------

 Background light extinction (1/Mm)

 (BEXTBK) -- No default ! BEXTBK = 52.2 !

 Percentage of particles affected by relative humidity

 (RHFRAC) -- No default ! RHFRAC = 51.7 !

 Additional inputs used for MVISBK = 6:

 --------------------------------------

 Extinction coefficients for hygroscopic species (modeled and

 background) are computed using a monthly RH adjustment factor

 in place of an hourly RH factor (VISB.DAT file is NOT needed).

 Enter the 12 monthly factors here (RHFAC). Month 1 is January.

 (RHFAC) -- No default ! RHFAC = 3.7, 3.7, 2.6, 2.6, 

 2.6, 3.4, 3.4, 3.4, 

 4.1, 4.1, 4.1, 3.7 !

 Additional inputs used for MVISBK = 2,3,6:

 ----------------------------------------

 Background extinction coefficients are computed from monthly

 CONCENTRATIONS of ammonium sulfate (BKSO4), ammonium nitrate (BKNO3),

 coarse particulates (BKPMC), organic carbon (BKOC), soil (BKSOIL), and

 elemental carbon (BKEC). Month 1 is January.

 (ug/m**3)

 (BKSO4) -- No default ! BKSO4 = 0.3, 0.3, 0.3, 0.3, 

 0.3, 0.3, 0.3, 0.3, 

 0.3, 0.3, 0.3, 0.3 !

 (BKNO3) -- No default ! BKNO3 = 0.0, 0.0, 0.0, 0.0, 

 0.0, 0.0, 0.0, 0.0, 

 0.0, 0.0, 0.0, 0.0 !

 (BKPMC) -- No default ! BKPMC = 0.0, 0.0, 0.0, 0.0, 

 0.0, 0.0, 0.0, 0.0, 

 0.0, 0.0, 0.0, 0.0 !

 (BKOC) -- No default ! BKOC = 0.0, 0.0, 0.0, 0.0, 

 0.0, 0.0, 0.0, 0.0, 

 0.0, 0.0, 0.0, 0.0 !

 (BKSOIL) -- No default ! BKSOIL= 8.5, 8.5, 8.5, 8.5, 

 8.5, 8.5, 8.5, 8.5, 

 8.5, 8.5, 8.5, 8.5 !

 (BKEC) -- No default ! BKEC = 0.0, 0.0, 0.0, 0.0, 

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 0.0, 0.0, 0.0, 0.0, 

 0.0, 0.0, 0.0, 0.0 !

 Additional inputs used for MVISBK = 2,3,5,6:

 ------------------------------------------

 Extinction due to Rayleigh scattering is added (1/Mm)

 (BEXTRAY) -- Default: 10.0 ! BEXTRAY = 10.0 !

!END!

-------------------------------------------------------------------------------

INPUT GROUP: 3 -- Output options

--------------

Output Units

------------

 Units for All Output (IPRTU) -- Default: 1 ! IPRTU = 1 !

 for for

 Concentration Deposition

 1 = g/m**3 g/m**2/s

 2 = mg/m**3 mg/m**2/s

 3 = ug/m**3 ug/m**2/s

 4 = ng/m**3 ng/m**2/s

 5 = Odour Units

 Visibility: extinction expressed in 1/Mega-meters (IPRTU is ignored)

Averaging time(s) reported

--------------------------

 1-hr averages (L1HR) -- Default: T ! L1HR = F !

 3-hr averages (L3HR) -- Default: T ! L3HR = F !

 24-hr averages (L24HR) -- Default: T ! L24HR = T !

 Run-length averages (LRUNL) -- Default: T ! LRUNL = F !

 User-specified averaging time in hours - results for

 an averaging time of NAVG hours are reported for

 NAVG greater than 0:

 (NAVG) -- Default: 0 ! NAVG = 0 !

Types of tabulations reported

------------------------------

 1) Visibility: daily visibility tabulations are always reported

 for the selected receptors when ASPEC = VISIB.

 In addition, any of the other tabulations listed

 below may be chosen to characterize the light

 extinction coefficients.

 [List file or Plot/Analysis File]

 2) Top 50 table for each averaging time selected

 [List file only]

 (LT50) -- Default: T ! LT50 = F !

 3) Top 'N' table for each averaging time selected

 [List file or Plot file]

 (LTOPN) -- Default: F ! LTOPN = T !

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 -- Number of 'Top-N' values at each receptor

 selected (NTOP must be <= 4)

 (NTOP) -- Default: 4 ! NTOP = 4 !

 -- Specific ranks of 'Top-N' values reported

 (NTOP values must be entered)

 (ITOP(4) array) -- Default: ! ITOP = 1 , 2 , 3 , 4 !

 1,2,3,4

 4) Threshold exceedance counts for each receptor and each averaging

 time selected

 [List file or Plot file]

 (LEXCD) -- Default: F ! LEXCD = F !

 -- Identify the threshold for each averaging time by assigning a

 non-negative value (output units).

 -- Default: -1.0

 Threshold for 1-hr averages (THRESH1) ! THRESH1 = -1.0 !

 Threshold for 3-hr averages (THRESH3) ! THRESH3 = -1.0 !

 Threshold for 24-hr averages (THRESH24) ! THRESH24 = 3.0E-01 !

 Threshold for NAVG-hr averages (THRESHN) ! THRESHN = -1.0 !

 -- Counts for the shortest averaging period selected can be

 tallied daily, and receptors that experience more than NCOUNT

 counts over any NDAY period will be reported. This type of

 exceedance violation output is triggered only if NDAY > 0.

 Accumulation period(Days)

 (NDAY) -- Default: 0 ! NDAY = 0 !

 Number of exceedances allowed

 (NCOUNT) -- Default: 1 ! NCOUNT = 1 !

 5) Selected day table(s)

 Echo Option -- Many records are written each averaging period

 selected and output is grouped by day

 [List file or Plot file]

 (LECHO) -- Default: F ! LECHO = F !

 Timeseries Option -- Averages at all selected receptors for

 each selected averaging period are written to timeseries files.

 Each file contains one averaging period, and all receptors are

 written to a single record each averaging time.

 [TSttUUUU.DAT files]

 (LTIME) -- Default: F ! LTIME = F !

 -- Days selected for output

 (IECHO(366)) -- Default: 366*0

 ! IECHO = 366*0 !

 (366 values must be entered)

Plot output options

-------------------

 Plot files can be created for the Top-N, Exceedance, and Echo

 tables selected above. Two formats for these files are available,

 DATA and GRID. In the DATA format, results at all receptors are

 listed along with the receptor location [x,y,val1,val2,...].

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 In the GRID format, results at only gridded receptors are written,

 using a compact representation. The gridded values are written in

 rows (x varies), starting with the most southern row of the grid.

 The GRID format is given the .GRD extension, and includes headers

 compatible with the SURFER(R) plotting software.

 A plotting and analysis file can also be created for the daily

 peak visibility summary output, in DATA format only.

 Generate Plot file output in addition to writing tables

 to List file?

 (LPLT) -- Default: F ! LPLT = T !

 Use GRID format rather than DATA format,

 when available?

 (LGRD) -- Default: F ! LGRD = F !

Additional Debug Output

-----------------------

 Output selected information to List file

 for debugging?

 (LDEBUG) -- Default: F ! LDEBUG = T !

!END!

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