State of Missouri 

Regional Haze Plan 

Missouri Air Conservation Commission 

Adopted: July 29, 2009

Missouri Department of Natural Resources 

Division of Environmental Quality 

Air Pollution Control Program 

P.O. Box 176 

1659 East Elm Street 

Jefferson City, Missouri 65102 

Telephone (573) 751-4817 
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TABLE of CONTENTS 

LIST OF FIGURES.....................................................................................................................................................6

LIST OF TABLES.......................................................................................................................................................7

EXECUTIVE SUMMARY .........................................................................................................................................8

1.0 BACKGROUND - FEDERAL REGIONAL HAZE REGULATION............................................................11

1.1 FEDERAL REGIONAL HAZE RULE .........................................................................................................11

1.2 CLASS I AREAS.....................................................................................................................................12

2.0 GENERAL PLANNING PROVISIONS...........................................................................................................14

2.1 PLAN SUBMISSION................................................................................................................................14

2.2 LEGAL AUTHORITY ..............................................................................................................................14

2.3 PUBLIC HEARING NOTICE AND CERTIFICATION....................................................................................14

2.4 COMMENTS, RESPONSES, AND EXPLANATIONS OF CHANGE .................................................................14

2.5 MISSOURI AIR CONSERVATION COMMISSION ADOPTION CERTIFICATION............................................15

2.6 COMMITMENT TO REVISE PLAN............................................................................................................15

3.0 REGIONAL PLANNING ..................................................................................................................................16

4.0 PLAN COORDINATION AND CONSULTATION .......................................................................................18

4.1 CENTRAL CLASS I AREAS CONSULTATION ...........................................................................................18

4.2 OTHER STATE CONSULTATIONS ...........................................................................................................19

5.0 ASSESSMENT OF BASELINE AND CURRENT CONDITIONS AND ESTIMATE OF NATURAL 

CONDITIONS ...........................................................................................................................................................25

5.1 VISIBILITY REQUIREMENTS ..................................................................................................................25

5.2 BASELINE VISIBILITY CONDITIONS.......................................................................................................27

5.3 NATURAL VISIBILITY CONDITIONS.......................................................................................................29

6.0 MONITORING STRATEGY............................................................................................................................30

6.1 MONITORING REQUIREMENTS ..............................................................................................................30

6.2 CURRENT MONITORING STRATEGY ......................................................................................................30

6.3 FUTURE MONITORING STRATEGY.........................................................................................................32

6.4 SPECIAL MONITORING STUDIES............................................................................................................33

7.0 EMISSIONS INVENTORY...............................................................................................................................34

7.1 2002 AND 2018 EMISSIONS INVENTORY SUMMARY..............................................................................34

7.2 OVERVIEW OF EMISSIONS INVENTORY DEVELOPMENT ........................................................................35

7.2.1 Point Sources ..................................................................................................................................35

7.2.2 Area Sources ...................................................................................................................................36

7.2.3 Offroad Mobile Sources..................................................................................................................38

7.2.4 Onroad Mobile Sources ..................................................................................................................39

7.2.5 Biogenic Emissions.........................................................................................................................40

7.3 PERIODIC UPDATES OF EMISSIONS INVENTORIES .................................................................................40

8.0 MODELING ASSESSMENT ............................................................................................................................42

8.1 MODELING REQUIREMENTS..................................................................................................................42

8.2 MODEL INPUTS .....................................................................................................................................43

8.2.1 Selection of Episodes......................................................................................................................43

8.2.2 Selection of Modeling Domain .......................................................................................................43

8.2.3 Emission Inventories.......................................................................................................................43
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8.2.4 Meteorology....................................................................................................................................44

8.3 MODEL PERFORMANCE EVALUATION...................................................................................................44

8.4 BASE G MODEL SIMULATIONS .............................................................................................................45

8.4.1 2018 Base G visibility projections ..................................................................................................45

8.4.2 Other RPO’s visibility projections..................................................................................................50

9.0 BEST AVAILABLE RETROFIT TECHNOLOGY (BART).........................................................................51

9.1 BART REQUIREMENTS.........................................................................................................................51

9.2 BART – ELIGIBLE SOURCES IN STATE OF MISSOURI............................................................................51

9.3 DETERMINATION OF SOURCES SUBJECT TO BART...............................................................................54

9.3.1 University of Missouri-Columbia ...................................................................................................62

9.3.2 Noranda...........................................................................................................................................64

9.3.3 Independence Power and Light – Blue Valley................................................................................67

9.3.4 Marshall Municipal Utilities...........................................................................................................68

9.3.5 Columbia Municipal Power Plant ...................................................................................................69

9.3.6 BASF Corporation - Palmyra..........................................................................................................70

9.3.7 Doe Run - Buick .............................................................................................................................72

9.3.8 Holcim - Clarksville........................................................................................................................73

10.0 REASONABLE PROGRESS GOALS ...........................................................................................................80

10.1 REASONABLE PROGRESS GOAL REQUIREMENTS ..................................................................................80

10.2 MISSOURI REASONABLE PROGRESS GOAL ...........................................................................................81

10.2.1 Cost and time necessary for compliance factor analysis by EPA .........................................................81

10.2.2 Cost analysis by CENRAP ...................................................................................................................83

10.2.3 Four-factor analysis by MRPO .............................................................................................................83

10.2.3.1 Cost of compliance and remaining useful life................................................................................84

10.2.3.2 Energy and non-air quality environmental impacts of compliance ...............................................84

10.2.4 Missouri reasonable progress goals ......................................................................................................85

10.3 CONSULTATION ....................................................................................................................................85

10.4 REPORTING...........................................................................................................................................86

11.0 LONG-TERM STRATEGY TO REACH REASONABLE PROGRESS GOALS.....................................87

11.1 LONG-TERM STRATEGY REQUIREMENTS..............................................................................................87

11.2 CONSULTATION ....................................................................................................................................87

11.3 SHARE OF EMISSION REDUCTIONS........................................................................................................87

11.4 LONG-TERM STRATEGY COMPONENTS .................................................................................................88

11.4.1 Ongoing air pollution control programs – “on the books” controls ................................................88

11.4.1.1 Clean Air Interstate Rule (CAIR)..................................................................................................89

11.4.1.2 BART.............................................................................................................................................93

11.4.1.3 Other federal ongoing air pollution control programs..................................................................94

11.4.1.4 NOX SIP Call .................................................................................................................................95

11.4.2 Additional controls beyond RPG modeling demonstration .................................................................97

11.4.2.1 SO2 and NOX RACT in St Louis....................................................................................................97

11.4.2.2 Illinois Multi-Pollutant Regulation...............................................................................................97

11.4.2.3 Regional Controls proposed by Alpine Geophysics (Alpine)........................................................98

11.4.3 Measures to mitigate the impacts of construction activities............................................................98

11.4.4 Source retirement and replacement schedules.................................................................................98

11.4.5 Smoke Management Plan................................................................................................................98

11.4.6 Enforceability of Emission Limitations and Control Measures ......................................................99

11.4.7 Anticipated net effect on visibility resulting from projected changes to emissions ......................100

11.5 FIVE-YEAR REVIEW ...........................................................................................................................100

12.0 COMPREHENSIVE PERIODIC PLAN REVISIONS ...............................................................................101

13.0 DETERMINATION OF THE ADEQUACY OF THE EXISTING PLAN ...............................................103
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14.0 REFERENCE INFORMATION...................................................................................................................105

14.1 LIST OF REFERENCES..........................................................................................................................105

14.2 LIST OF ACRONYMS AND ABBREVIATIONS .........................................................................................106

14.3 LIST OF APPENDICES...........................................................................................................................108
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LIST of FIGURES 

Figure 3.1: Geographical Areas of Regional Planning Organizations........................................................................16

Figure 4.1: Causes of Haze Study II, EIP sulfate mappings .......................................................................................22

Figure 4.2: Causes of Haze Study II, EIP nitrate mappings .......................................................................................23

Figure 4.3: PSAT Source Analysis for Missouri modeling demonstration (as part of CENRAP Analysis)...............24

Figure 5.1: Determination of Natural Background .....................................................................................................26

Figure 6.1: Hercules Glades IMPROVE Monitoring Station .....................................................................................31

Figure 6.2: Mingo IMPROVE Monitoring Station.....................................................................................................31

Figure 6.3: El Dorado Springs IMPROVE Protocol Monitoring Station ...................................................................32

Figure 8.1a: 2018 Visibility Projections and 2018 URP Glidepaths in deciview for Hercules Glades, Missouri, and 

Worst 20% days using 2002/2018 Base G CMAQ 36 km modeling results. ......................................................48

Figure 8.1b: 2018 Visibility Projections and 2018 URP Glidepaths in deciview for Hercules Glades, Missouri, and 

Best 20% days using 2002/2018 Base G CMAQ 36 km modeling results. .........................................................48

Figure 8.2a: 2018 Visibility Projections and 2018 URP Glidepaths in deciview for Mingo, Missouri, and Worst 

20% days using 2002/2018 Base G CMAQ 36 km modeling results. .................................................................49

Figure 8.2b: 2018 Visibility Projections and 2018 URP Glidepaths in deciview for Mingo, Missouri, and Best 20% 

days using 2002/2018 Base G CMAQ 36 km modeling results. .........................................................................49

Figure 12.1: 5-Year Progress Review Criteria and Actions......................................................................................102
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LIST of TABLES

Table 5.1: Baseline Visibility Conditions for Missouri Class I Areas........................................................................28

Table 5.2: Natural Background Conditions for the Class 1 Areas in Missouri...........................................................29

Table 7.1: 2002 Missouri Emissions Inventory Summary..........................................................................................34

Table 7.2: 2018 Missouri Emissions Inventory Summary..........................................................................................34

Table 9.1: Facilities with BART-eligible Units in the State of Missouri....................................................................52

Table 9.2: Units Removed from BART Consideration Due to Shutdown or Federal Permit Requiring Shutdown ...55

Table 9.3: CALPUFF/CALPOST Screening Results .................................................................................................58

Table 9.4: Number of Days over the 0.5 Deciview Threshold ...................................................................................60

Table 9.5: Grid Structure for Refined Terrain, Land Use, and CALMET Analyses ..................................................62

Table 9.6: UMC Refined Analysis Results (Boiler PM Speciation Profile)...............................................................63

Table 9.7: UMC Refined Analysis Results (PM10=PMF) Method 2 ..........................................................................63

Table 9.8: UMC Refined Analysis Results (PM10=PMF) Method 6 ..........................................................................63

Table 9.9: Noranda Refined Analysis Results (Original Submittal)...........................................................................66

Table 9.10: Noranda Refined Analysis Results (Revised CALMET) ........................................................................67

Table 9.11: Independence Power and Light Refined Analysis Results ......................................................................68

Table 9.12: Marshall Municipal Utilities Refined Analysis Results...........................................................................69

Table 9.13: Columbia Municipal Utilities Refined Analysis Results .........................................................................70

Table 9.14: BASF Corporation Refined Analysis Results..........................................................................................72

Table 9.15: Doe Run Buick Refined Sensitivity Results............................................................................................73

Table 9.16: Holcim - Clarksville Refined Analysis Results .......................................................................................74

Table 9.17: Holcim - Clarksville Post-Submittal Refined Analysis Results...............................................................75

Table 9.18: Holcim - Clarksville BART Limit Refined Analysis Results..................................................................77

Table 10.1: Uniform Rate of Progress and Reasonable Progress Goals for Class I areas in Missouri .......................85

Table 11.1: CAIR NOX Emissions Allocation (tons/yr) .............................................................................................90

Table 11.2: CAIR SO2 Emissions Allocation (tons/yr) ..............................................................................................92

Table 11.3: NOX SIP Call Emissions Allocation (tons/ozone season)........................................................................96
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EXECUTIVE SUMMARY 

In 1977, Congress passed amendments to the Clean Air Act (CAA) with the goal of improving 

visibility in Class I federal areas, such as national parks and wilderness areas. Following the 

enactment of the 1977 CAA amendments, some measures were taken to address issues such as 

“plume blight” from specific pollution sources, but little was done to improve the regional haze 

issues in the Eastern United States. Congress passed additional amendments to the CAA in 1990 

that authorized additional research and regular progress updates. 

 

The U.S. Environmental Protection Agency (EPA) adopted the federal Regional Haze Rule on 

July 1, 1999. The Regional Haze Rule and the CAA require consultation between the states, 

tribes and the Federal Land Managers (FLMs) for managing Class I areas. Since regional haze 

often results from pollution emitted across broad regions, this multi-state planning effort will 

help in developing the most cost-effective controls for regional haze. This consultation process 

will provide a coordinated effort to achieve the federal visibility requirements and aid in 

developing regional strategies for meeting progress goals. 

The Regional Haze Rule went into effect on August 30, 1999. The EPA selected five Regional 

Planning Organizations (RPOs) to aid in the coordination required to achieve the national 

visibility goals of Class I areas by 2064. One RPO, the Central Regional Air Planning 

Association (CENRAP), is comprised of nine states that make up the midsection of the 

contiguous United States, including Missouri. Missouri has two federal Class I areas (Hercules 

Glades and Mingo) within its borders and is in close proximity with two Class I areas in 

Arkansas (Caney Creek and Upper Buffalo). 

Between 2000 and 2007, Missouri participated in the CENRAP workgroup process to develop 

technical analyses and control strategies for the Regional Haze Plan. Missouri determined the 

baseline visibility conditions for each Class I area using monitoring data collected from 2000 

through 2004 and compared them to the natural background conditions. The technical analyses 

showed that both of the Class I areas in Missouri will meet the 2018 Reasonable Progress Goal 

(RPG). The analyses in this Regional Haze Plan demonstrate that the 2018 visibility goals for 
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Mingo and Hercules Glades will be largely achieved from EGU (Electric Generating Unit) 

emission reductions resulting from the federal Clean Air Interstate Rule (CAIR) program. 

Missouri long-term strategy also consists of other air pollution programs including Missouri 

NOX State Implementation Plan (SIP) call, Tier 2 vehicle emission standards, other states’ SIP 

controls, other states’ Best Available Retrofit Technology (BART) controls, as well as other 

programs. Additional controls not included in the RPG modeling demonstration are also 

identified in the long-term strategy chapter of the plan and may be considered during the fiveyear review. 

Missouri has satisfied the consultation requirement of the federal Regional Haze Rule through 

the consultation process that was used to develop this plan. The consultation process is 

documented in a consultation plan that was used to attain and share the technical information 

necessary in developing this Regional Haze Plan for the Central Class I areas. A copy of the 

consultation plan has been provided as an appendix to this plan. In addition, Missouri has 

consulted with and continues to consult with other states that have included Missouri in their 

consultation process to meet their Regional Haze Rule requirements. 

A BART analysis was used to assure that the federal Regional Haze Rule requirements were met. 

This analysis included BART source development, screen-modeling analyses and refined 

modeling. As a result of the analysis and modeling, Missouri has identified one BART-eligible 

source in Missouri that must undergo a BART control evaluation to ensure it meets the Regional 

Haze Rule requirements. 

The Missouri Department of Natural Resources (department) Air Pollution Control Program will 

submit this Regional Haze Plan to the EPA for inclusion in the Missouri SIP to meet the 

requirements of EPA’s Regional Haze Rule. A public hearing was held for this plan on 

December 6, 2007, and the plan was adopted by the Missouri Air Conservation Commission 

(MACC) on February 7, 2008. A public hearing was held for a revision to this plan on June 25, 

2009, and the revised plan was adopted by the MACC on July 29, 2009. 

Missouri will continue to coordinate with other states, FLMs, EPA, CENRAP, and other RPOs to 
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maintain/improve the visibility in Missouri’s Class I areas. This coordination will include fiveyear progress reports and any necessary SIP revisions. If deemed necessary, there will be face to 

face consultation meetings. 
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1.0 BACKGROUND - FEDERAL REGIONAL HAZE REGULATION 

1.1 FEDERAL REGIONAL HAZE RULE

In amendments to the CAA in 1977, Congress added Section 169 (42 U.S.C. 7491), setting forth 

the following national visibility goal of restoring pristine conditions in national parks and 

wilderness areas: 

Congress hereby declares as a national goal the prevention of any future, and the 

remedying of any existing, impairment of visibility in mandatory Class I Federal 

areas which impairment results from man-made air pollution. 

Over the following years, modest steps were taken to address the visibility problems in Class I 

areas. The control measures taken mainly addressed plume blight from specific pollution 

sources and did little to address regional haze issues in the Eastern United States. Plume blight is 

the visual impairment of air quality that manifests itself as a coherent plume. This results from 

specific sources, such as a power plant smokestack, emitting pollutants into a stable atmosphere. 

The pollutants are then transported in some direction with little or no vertical mixing. 

When the CAA was amended in 1990, Congress added Section 169B (42 U.S.C. 7492), 

authorizing further research and regular assessments of the progress made so far. In 1993, the 

National Academy of Sciences concluded that “current scientific knowledge is adequate and 

control technologies are available for taking regulatory action to improve and protect visibility.”1

In addition to authorizing creation of visibility transport commissions and setting forth their 

duties, Section 169B(f) of the CAA specifically mandated creation of the Grand Canyon 

Visibility Transport Commission (GCVTC) to make recommendations to the EPA for the region 

affecting the visibility of the Grand Canyon National Park. Following four years of research and 

policy development, the GCVTC submitted its report to EPA in June 1996. This report, as well 

 

1 National Research Council. Protecting Visibility in National Parks and Wilderness Areas. National Academy Press. 

Washington, DC: 1993. 
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as the many other research reports prepared by the GCVTC, contributed invaluable information 

to EPA in its development of the federal Regional Haze Rule. 

EPA’s Regional Haze Rule was adopted July 1, 1999, and went into effect on August 30, 1999. 

The Regional Haze Rule aimed at achieving national visibility goals by 2064. This rulemaking 

addressed the combined visibility effects of various pollution sources over a wide geographic 

region. This broad scope meant that many states – even those without Class I areas – would be 

required to participate in haze-reduction efforts. EPA designated five RPOs to assist with the 

coordination and cooperation needed to address the visibility issue. Those states that make up 

the midsection of the contiguous United States were designated as CENRAP. 

On May 24, 2002, the U.S. Court of Appeals, D.C. District Court ruled on the challenge brought 

by the American Corn Growers Association against EPA’s Regional Haze Rule of 1999. The 

Court remanded to EPA the BART provisions of the rule and denied the industry’s challenge to 

the haze rule goals of natural visibility and no degradation. EPA has proposed revisions to the 

Regional Haze Rule pursuant to the remand. To facilitate the review of this SIP submittal by the 

EPA, FLMs, stakeholders, and the public; a guide is provided in 40 CFR 51.308, Regional Haze 

Program Requirements (Appendix A). 

1.2 CLASS I AREAS 

The State of Missouri has the following Class I areas within its borders: 

Hercules Glades Wilderness Area 

Situated in southwest Missouri, Taney County, Hercules Glades Wilderness Area (Hercules 

Glades) is managed by the United States Department of Agriculture (USDA) Forest Service as 

part of the Mark Twain National Forest. The area includes 12,315 acres located in some of the 

most rugged hills of the Missouri Ozarks. The closest urban area is the Springfield/Branson 

metropolitan statistical area, 40 miles to the west/northwest. 

Mingo National Wildlife Refuge

The Mingo National Wildlife Refuge (Mingo) is managed by the U.S. Fish and Wildlife Service. 

The refuge is situated in southeast Missouri, along the Mississippi Flyway. Only a portion of the 
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refuge is a Class I area (7,730 acres of a total 21,676 acres). Memphis to the south and St. Louis 

to the north are some of the largest urban areas nearby, although there are a few smaller 

population centers mostly to the east. Proximity to sources in the Ohio River Valley is a 

consideration. 

In accordance with 40 CFR 51.308, Missouri has identified emissions sources within Missouri 

that have or may have impacts on the following Missouri Class I areas: Hercules Glades and 

Mingo. Emissions from Missouri may also contribute to visibility impairment in other states’ 

Class I areas, such as the Caney Creek and Upper Buffalo Wilderness Areas in Arkansas (Upper 

Buffalo). 

Improved visibility will lead to greater enjoyment of recreational opportunities at Hercules 

Glades and Mingo. The tourists drawn to the scenic beauty and recreational opportunities of 

each of these areas provide revenue to the respective regions. Missouri expects improved 

visibility of Hercules Glades and Mingo to provide not only enhanced scenic beauty, but also 

improved health benefits for people who are more susceptible to respiratory problems. 
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2.0 GENERAL PLANNING PROVISIONS 

2.1 PLAN SUBMISSION

Pursuant to the requirements of 51.308(a) and (b), this Missouri Regional Haze Plan is being 

submitted for inclusion into the SIP as adopted to meet the requirements of EPA’s Regional 

Haze Rule that was implemented to comply with requirements set forth in the CAA. Elements of 

this plan address the core requirements pursuant to 40 CFR 51.308(d) and the BART 

components of 40 CFR 50.308(e). In addition, this plan addresses regional planning; state/tribe 

and FLM coordination; and contains a commitment to provide plan revisions and adequacy 

determinations. Missouri has adopted this plan submittal in accordance with state laws and rules. 

2.2 LEGAL AUTHORITY

The MACC is granted the legal authority to develop and implement regulations regarding air 

pollution under section 643.050 of the Revised Statues of Missouri. 

2.3 PUBLIC HEARING NOTICE AND CERTIFICATION

The department’s Air Pollution Control Program is required to announce a public hearing at least 

30 days prior to holding such a hearing. Announcements were submitted to newspapers at least 

30 days prior to the public hearing. The public hearing for this Regional Haze Plan occurred on 

December 6, 2007 and the public hearing for the revision to the plan occurred on June 25, 2009. 

Attached in Appendix B are the public hearing notices, along with certification of publication of 

the public notices for the Regional Haze Plan public hearings. 

2.4 COMMENTS, RESPONSES, AND EXPLANATIONS OF CHANGE

Attached in Appendix C are the department’s Air Pollution Control Program responses to 

comments received during the open public comment periods for this region haze plan. The 

comment period on the Regional Haze Plan was open until December 13, 2007, seven days after 

the Public Hearing that was held on December 6, 2007. The comment period on the revision to 

the Regional Haze Plan was open until July 2, 2009, seven days after the Public Hearing that was 

held on June 25, 2009. The department’s Air Pollution Control Program is required to respond 
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to all comments received by either amending the plan or explaining the reasoning for not making 

an amendment. 

2.5 MISSOURI AIR CONSERVATION COMMISSION ADOPTION CERTIFICATION

Attached in Appendix D are the MACC adoption certifications to demonstrate the approval of 

the Regional Haze Plan by the Commission. 

2.6 COMMITMENT TO REVISE PLAN 

Consultation between the states and the FLMs will continue as the federal regional haze program 

progresses. The consultation will continue via participation in CENRAP, and if CENRAP is no 

longer operating, Missouri will lead the consultation with other states and FLMs for meeting 

Missouri’s goals. This effort will include five-year progress reports and development and review 

of any plan revisions deemed necessary. It will also provide for consideration of any other 

programs that are implemented and have the potential to contribute to impairment of visibility in 

Class I areas. 
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3.0 REGIONAL PLANNING 

In 1999, EPA and affected states/tribes agreed to create five RPOs to facilitate interstate 

coordination on regional haze plan submittals and Tribal Implementation Plans (TIPs). Figure 

3.1 shows a map of all five RPOs. The State of Missouri is a member of the CENRAP RPO. 

Members of CENRAP include the following states: Arkansas, Iowa, Kansas, Louisiana, 

Minnesota, Missouri, Nebraska, Oklahoma, and Texas. 

Figure 3.1: Geographical Areas of Regional Planning Organizations 

The governing body of CENRAP is the Policy Oversight Group (POG). The POG is made up of 

18 voting members representing the states and tribes within the CENRAP region and non-voting 

members representing local agencies, the EPA, the Fish and Wildlife Service, Forest Service and 

National Park Service. The POG facilitates communication with FLMs, stakeholders, the public, 

and CENRAP staff. 

Since its inception, CENRAP has established an active committee structure to address both 

technical and non-technical issues related to regional haze. The work of CENRAP is 
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accomplished through five standing workgroups: Monitoring; Emission Inventory; Modeling; 

Communications; and Implementation and Control Strategies. Participation in workgroups is 

open to all interested parties. Ad hoc workgroups may be formed by the POG to address specific 

issues. Ultimately, the CENRAP POG makes policy decisions. 

CENRAP has adopted the approach that the Regional Haze Rule requires the “States to 

establish goals and emission reduction strategies for improving visibility in all 156 mandatory 

Class I parks and wilderness areas.” The rule also encouraged states and tribes to work together 

in regional partnerships. 

This plan utilizes data analysis, modeling results and other technical support documents prepared 

for CENRAP members. By coordinating with CENRAP and other RPOs, Missouri has worked 

to ensure that its long-term strategy provides sufficient reductions to mitigate impacts of sources 

from Missouri on affected Class I areas. Data analyses, modeling results and other technical 

support documents are provided to CENRAP members through either CENRAP’s website or 

through a file transfer protocol (ftp) that allows users to copy files between their local system and 

CENRAP’s system that they can reach on the CENRAP network. 
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4.0 PLAN COORDINATION AND CONSULTATION 

4.1 CENTRAL CLASS I AREAS CONSULTATION

40 CFR 51.308(i) requires coordination between states/tribes and the FLMs. FLMs are an 

integral part of CENRAP’s POG and the membership on standing committees. FLMs have 

contributed to the development of technical and non-technical work as a result of that 

participation. In addition, opportunities have been provided by CENRAP for FLMs to review 

and comment on each of the technical documents developed by CENRAP and included in this 

plan. Missouri has provided agency contacts to the FLMs as required. In development of this 

plan, the FLMs were consulted in accordance with the provisions of 51.308(i)(2). 

Missouri provided FLMs an opportunity for consultation and an opportunity to hold a face to 

face meeting, if deemed necessary. All of the consultation for this plan was conducted by 

conference call with no need expressed for a face to face meeting and a draft of the plan was 

provided at least 60 days prior to holding the public hearing on the Regional Haze Plan. 

During the consultation process, the FLMs were given the opportunity to address their: 

 Assessment of the impairment of visibility in any Class I areas 

 Recommendations on the development of RPGs 

 Recommendations on the development and implementation of strategies to address 

visibility impairment. 

According to 40 CFR 51.308(d)(3)(i), Missouri is required to consult with other states/tribes to 

develop coordinated emission strategies. This requirement applies both when emissions from the 

state are reasonably anticipated to contribute to visibility impairment in Class I areas outside the 

state and when emissions from other states/tribes are reasonably anticipated to contribute to 

visibility impairment in Class I areas within the state. 

Missouri has consulted with other states/tribes in CENRAP, Visibility Improvement State and 

Tribal Association of the Southeast (VISTAS), the Midwest Regional Planning Organization 

(MRPO), FLMs and EPA Regions 5, 6 and 7 on development of coordinated strategies for 
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Central Class I areas, including Mingo, Hercules Glades, Upper Buffalo, and Caney Creek. 

Technical analyses, such as Area of Influence (AOI) and source apportionment, were developed 

as part of consultation planning to determine contributing states (Appendix E). 

Missouri provided the Regional Haze Plan to the FLMs for review on August 23, 2007 and 

notified the FLMs that a public hearing would be held on this plan at a later date. The FLMs 

provided early comments on the draft plan and a conference call between Missouri, FLMs, and 

EPA Region 7 was conducted on September 25, 2007 to discuss the comments. Missouri 

considered all comments the FLMs provided on the early draft of the plan. 

Regional modeling and other findings were used to develop RPGs for the Arkansas and Missouri 

Class I areas based on the existing and proposed controls through both state and federal 

requirements. It was also determined that these RPGs will meet the established URP goals by 

2018. The consultation process determined which states significantly impacted the Arkansas and 

Missouri Class I areas. 

Missouri is reasonably anticipated to contribute to the following Class I areas: 

1) Mingo National Wildlife Refuge, Missouri 

2) Hercules Glades Wilderness, Missouri 

3) Upper Buffalo Wilderness Area, Arkansas 

4) Caney Creek Wilderness Area, Arkansas 

The state’s coordination with FLMs on long-term strategy development is described in Chapter 

11. The consultation was completed based on a determination that reasonable progress was 

achieved by contributing states. 

4.2 OTHER STATE CONSULTATIONS

The consultation processes for the Wichita Mountains (WIMO) Class I area in Oklahoma was 

completed prior to the March 2008 submittal of this plan. The Oklahoma Department of 

Environmental Quality indicated their belief that Missouri sources impact WIMO. However, in 

response to the Oklahoma consultation letter, Missouri replied with a letter recommending that 

the rationale for determining contributing states deserves further examination. A more inclusive 
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methodology for the Central Class I areas with four different metrics (Particulate Matter Source 

Apportionment Technology (PSAT), PMF, AOI, and emission rate divided by five times the 

distance - Q/d) was used in a combined manner with three out of four positive results required 

before concluding that a particular state is contributing. The distance between WIMO and 

western Missouri’s Class I area is approximately 200-250 miles farther west. Because of this 

distance, it is counter-intuitive to assume that planned emission controls on Missouri sources 

would be significant enough. It seems likely that Missouri would not be included as significant 

based on this level/type of PSAT analysis, and emissions/source distance ratio. 

It is also not clear that additional controls in Missouri would be reasonable to reduce the 

visibility in WIMO. Based on the PSAT analysis presented, over half the elevated point-source 

impacts to WIMO are due to sources in Oklahoma, Texas, and Louisiana and most of the area 

source impacts are due to Oklahoma and Texas sources. Point and area are the two largest 

emission sectors. Controls appear likely to be more efficient in those states, on a cost-per-ton 

basis, than additional controls in Missouri. 

Consultation processes for the Minnesota Class I areas was also conducted prior to the March 

2008 submittal of this plan. The Minnesota Pollution Control Agency indicated that it believes 

that Missouri impacts the Boundary Waters, but not Voyageurs. 

Minnesota identified Missouri as a contributing state based on LADCO 2002-2003 Trajectory 

analysis or LADCO 2018 PSAT modeling analysis at over a 5 percent total contribution to haze 

at either of their Class I areas. The criteria are met marginally at 5.2 percent for 2018 PSAT for 

the Boundary Waters area only. 

 

Analysis conducted as part of the Causes of Haze II Study2

 shows emissions for the northern 

Class I area at Voyageurs National Park indicating the high impact of Minnesota sources, with 

 

2 Causes of Haze II, 2005; Sullivan, Hafner, Brown, MacDonald, Raffuse, Penfold, Roberts, Sonoma Technology 
21

only small impact by out of state sources. Voyageurs and the Boundary Waters are very close in 

proximity, and the overall analysis was intended to apply regionally. The Emission Impact 

Potential mappings below underscore the impact of Minnesota sources on the area, and how 

controls on a relative few will provide much greater result than controls on sources outside 

Minnesota. Comparisons with Hercules Glades EIP show the difference in areas with significant 

external sources (Hercules) to areas with significant internal sources (Voyageurs, Boundary 

Waters). The conclusion reached in the Causes of Haze II is that for Voyageurs, and by 

geographic proximity, Boundary Waters, important emission source regions are internal 

(Minnesota and to a lesser extent North Dakota) on the 20 percent worst days. Area of Influence 

analysis for CENRAP states confirms that Level I Sulfate for both areas barely enters the 

northwest 20 miles of Missouri, not indicating strong source influence. 

The most recent CENRAP PSAT analysis, as Figure 4.3, shows most Minnesota anthropogenic 

sources with very high impacts on Boundary Waters, slightly more than 15 inverse megameters 

for 2002. For 2018 modeling, it remains at almost 14 inverse megameters. Of other states, only 

Wisconsin elevated point impacts are larger than 2 inverse megameters, and Missouri impacts 

are 1.6. Based on the AOI and PSAT analyses, it is not reasonable to control the Missouri 

sources at the same level as Minnesota sources to achieve a very small impact at the Boundary 

Waters Class I area. 

Missouri provided a written response to Minnesota regarding the Northern Class I Areas 

consultation. 

Since other states are still involved in their consultation process for their respective plans, 

Missouri will continue to participate in their consultation processes, as necessary. 
22

Figure 4.1: Causes of Haze Study II, EIP sulfate mappings 
23

Figure 4.2: Causes of Haze Study II, EIP nitrate mappings 
24

Figure 4.3: PSAT Source Analysis for Missouri modeling demonstration (as part of CENRAP Analysis) 
25

5.0 ASSESSMENT OF BASELINE AND CURRENT CONDITIONS AND 

ESTIMATE OF NATURAL CONDITIONS 

5.1 VISIBILITY REQUIREMENTS

The goal of the Regional Haze Rule is to restore natural visibility conditions to the 156 Class I 

areas identified in the 1977 CAA Amendments. Sec. 51.301(q) defines natural conditions: 

“Natural conditions includes naturally occurring phenomena that reduce visibility as measured in 

terms of light extinction, visual range, contrast, or coloration.” The regional haze plans must 

contain measures that make “reasonable progress” toward this goal by reducing anthropogenic 

emissions that cause haze. For each Class I area, there are three metrics of visibility that are part 

of the determination of reasonable progress: 

1) baseline conditions 

2) natural conditions 

3) current conditions 

Each of the three metrics includes the concentration data of the visibility pollutants as different 

terms in the light extinction algorithm, with respective extinction coefficients and relative 

humidity (RH) factors. Total light extinction when converted to deciviews (dv) is calculated for 

the average of the 20 percent best and 20 percent worst visibility days. 

“Baseline” visibility is the starting point for the improvement of visibility conditions. It is the 

average of the Interagency Monitoring and PROtected Visual Environments (IMPROVE) 

monitoring data for 2000 through 2004 and can be thought of as “current” visibility conditions 

for this initial period. The comparison of initial baseline conditions to natural visibility 

conditions indicates the amount of improvement necessary to attain natural visibility by 2064. 

Natural visibility is determined by estimating the natural concentrations of visibility pollutants 

and then calculating total light extinction with the light extinction algorithm (Figure 5.1). Each 

state must estimate natural visibility levels for Class I areas within its borders in consultation 

with FLMs and other states (51.308(d)(2)). “Current conditions” are assessed every five years as 

part of the plan review where actual progress in reducing visibility impairment is compared to 

the reductions committed to in the plan (Appendix F, Chapter 4.0). 
26

Figure 5.1: Determination of Natural Background 

Consultation regarding the visibility metrics

Consultation among states is a requirement that is repeated in the Regional Haze Rule. As part 

of a “long-term strategy” for regional haze, a state whose emissions are “reasonably anticipated” 

to contribute to impairment in other states’ Class I area(s) must consult with those states and also 

consult with any states whose emissions affect its own Class I area(s) (sec. 51.308(d)(3)). 

A chief purpose of the RPO is to provide a means for states to confer on all aspects of the 

regional haze issue, including consultation on reasonable progress goals and long-term strategies, 

which are based on the current (baseline) and natural visibility determinations. This process is 

described in Chapter 3, Regional Planning. CENRAP has provided a forum for the member 

states and tribes to consult on the determination of baseline and natural visibility conditions in 

each of the Class I areas. 

Example: Rate that Would Achieve 

Natural Conditions in 60 Years 
27

In addition, states in CENRAP have conferred with neighboring Class I area states outside 

CENRAP, both individually and by way of the states’ RPO. 

Sec. 51.308(i) requires Class I area states’ coordination with FLMs that includes consultation on 

implementation, including the assessment of visibility impairment and recommendations 

regarding the reasonable progress goal and strategies for improvement. 

Through participation in CENRAP and as a state, Missouri has completed this regulatory 

requirement. Details of actions taken to meet this requirement are found in the Central Class I 

Areas Consultation Plan (Appendix E). 

5.2 BASELINE VISIBILITY CONDITIONS

During the five-year (2000-2004) baseline period, sites are required to have three valid years of 

data from which baseline conditions can be constructed. The Visibility Information Exchange 

Websystem (VIEWS) website (http://vista.cira.colostate.edu/views/) has posted particulate 

matter (PM)-species specific natural and baseline conditions based on the new IMPROVE 

algorithm. The new IMPROVE algorithm was developed by fitting reconstructed light 

extinction based on IMPROVE measured PM and nitrite (NO2) concentrations with actual colocated measured light extinction (e.g., nephelometer measurements. The VIEWS document, 

Revised IMPROVE Algorithm for Estimating Light Extinction from Particle Speciation Data,

posted under gray literature, explains the justification for the use of the new equation. Section II 

of this algorithm document, which provides more detail on the revised IMPROVE equation is 

included as Appendix G. The choice between use of the default or the refined equation for 

calculating the visibility metrics for each Class I area is made by the state in which the Class I 

area is located.3 It is with these calculations that the state develops a RPG for each Class I area, 

in consultation with other states whose emissions affect visibility in that park or wilderness area 

(sec. 51.308(d)(1)(iv)). 

Because it is based on more recent science which better exemplifies the observed light extinction 

values, Missouri, as well as other CENRAP states, has elected to perform their primary visibility 

 

3

 According to sec. 51.308(d)(2), the state will make the determinations of baseline and natural visibility conditions. 
28

projections using the new IMPROVE equation to calculate visibility metrics for the purpose of 

developing its reasonable progress goal (Appendix F, Section 4.2.1.1.3). 

Using these PM-species specific natural conditions and the curved extinction glidepaths, we can 

evaluate how well visibility extinction achieves the 2018 Uniform Rate of Progress (URP) goal 

on a species-by-species basis in accordance with 40 CFR 51.308(d)(2). 

The Mingo Class I area has an established baseline visibility of 13.76 dv for the cleanest 20 

percent of the sample days and 28.02 dv for the 20 percent worst visibility days, as indicated in 

Table 5.1. This is based on sampling data collected at the Mingo IMPROVE monitoring site, 

which was established by the IMPROVE sampling staff at the University of California-Davis via 

their protocols. For Mingo, because of a clogged Module C Inlet, carbon data was not available 

from June 2000 to January 2002. The resolution was a substitution protocol developed by 

Warren White using organic mass hydrogen (OMH) to develop a surrogate for organic mass 

carbon (OMC). Data filling was used to obtain sufficient data so that three-years of valid data 

were available from which baseline conditions could be calculated. The data filled IMPROVE 

database were prepared and made available on the VIEWS website, where more information on 

the data filling procedures can be found (http://vista.cira.colostate.edu/views/). 

The Hercules Glades Class I area has an established baseline visibility of 12.84 dv for the 

cleanest 20 percent of the sample days and 26.75 dv for the 20 percent worst visibility days. 

This is based on sampling data collected at the Hercules Glades IMPROVE monitoring site 

which was established by the IMPROVE sampling staff at the University of California-Davis via 

their protocols. 

Table 5.1: Baseline Visibility Conditions for Missouri Class I Areas 

Baseline Visibility Conditions 2000-2004 

Class 1 Area Average for 20% Worst 

Days (dv) 

Average for 20% Best 

Days (dv)

Mingo 28.02 13.76 

Hercules Glades 26.75 12.84 
29

5.3 NATURAL VISIBILITY CONDITIONS

EPA’s “Guidance for Estimating Natural Visibility Conditions Under the Regional Haze 

Program” (Sept 2003) provides states a “default” estimate of natural visibility. The default 

values of concentrations of visibility pollutants are based on a 1990 National Acid Precipitation 

Assessment Program report (Trijonis, J.C. 1990). In the guidance, the United States is divided 

into “East” and “West” along the western boundary of the states one tier west of the Mississippi 

River. This division divides the CENRAP states into “East” (MN, IA, MO, AR, and LA), with 

seven Class I areas, and “West” (NE, KS, OK, and TX), with three Class I areas. In the two 

equations, only sulfate (SO4) and organic carbon have different values, but the calculated dv 

difference is significant (see Appendix F, Section 4.2 for further discussion of the default 

equation). 

Using the New IMPROVE equation, Missouri has determined that natural visibility conditions 

for the Mingo Class I area is best represented by 12.40 dv for the 20 percent worst days (Table 

5.2). The Hercules Glades Wilderness Class I area is best represented by 11.30 dv for the 20 

percent worst days. Appendix F, Section 4.2.1.1.3 provides calculations, methodologies, and a 

discussion of the reasons for selection of the methodology and a demonstration of the 

appropriateness of these values for both Class I areas. 

Table 5.2: Natural Background Conditions for the Class 1 Areas in Missouri 

Class 1 area 20% Worst Days 

Goal (dv) 

20% Best Days 

Goal 

Mingo 12.40 No degradation 

Hercules Glades 11.30 No degradation 
30

6.0 MONITORING STRATEGY 

6.1 MONITORING REQUIREMENTS

Section 51.308(d)(4) of the federal Regional Haze Rule requires a monitoring strategy for 

measuring, characterizing, and reporting regional haze visibility impairment that is representative 

of all mandatory Class I areas within the State of Missouri. The monitoring strategy relies upon 

participation in the IMPROVE network. 

6.2 CURRENT MONITORING STRATEGY

Upon the creation of CENRAP, the newly formed Monitoring Workgroup identified large 

visibility data voids in Southern Arkansas, Iowa, Kansas, Southern Minnesota, Nebraska, and 

Oklahoma. Only five IMPROVE sites were located in the CENRAP region. Between 2000 and 

2003, five more IMPROVE sites and 15 IMPROVE protocol sites were installed. In Missouri, 

IMPROVE Sites are located at Hercules Glades and Mingo (Figures 6.1 and 6.2). An 

IMPROVE protocol sampler is located at the site near El Dorado Springs (Figure 6.3). Missouri 

commits to meet the requirements under 40 CFR 51.308(d)(4)(iv) to report to EPA visibility data 

for each of Missouri’s Class I areas annually. 

The filter samples from the IMPROVE modules are sent for analysis to the Crocker Nuclear 

Laboratory of the University of California in Davis and the data is posted to the IMPROVE 

website and the VIEWS website.4

 Details regarding the monitors (location, date of installation, 

etc., and monitoring data) are found at the VIEWS website. This fulfills Missouri’s reporting 

requirement of visibility data (electronic) under subsection (iv). 

 

4 The IMPROVE website can be found at: http://vista.cira.colostate.edu/improve/. The VIEWS website 

can be found at: http://vista.cira.colostate.edu/views/. 
31

Figure 6.1: Hercules Glades IMPROVE Monitoring Station 

Figure 6.2: Mingo IMPROVE Monitoring Station 
32

Figure 6.3: El Dorado Springs IMPROVE Protocol Monitoring Station 

6.3 FUTURE MONITORING STRATEGY

In order to assess progress in reducing visibility impairment in Class I areas, the existing 

IMPROVE and IMPROVE Protocol sites will be maintained contingent upon continued national 

funding to measure, characterize and report regional haze visibility impairment to satisfy 

requirements of subsection (i). If EPA elects to revise funding for this network, Missouri will 

evaluate the IMPROVE protocol site at El Dorado Springs. Any changes appropriate to 

continued monitoring of Regional Haze for the Missouri Class I areas will be evaluated during 

the Missouri five-year review. The five-year review will include the following aspects: 

 QA IMPROVE data from Mingo and Hercules Glades. 

 Calculate current visibility conditions for most impaired and least impaired days. 

 Calculate differences between current conditions and baseline conditions. 

 Determine whether RPGs are being met. 

Missouri will also evaluate technology changes and the need for new monitors as appropriate. 
33

6.4 SPECIAL MONITORING STUDIES

Special monitoring in the CENRAP region for ammonia was conducted from November 1, 2003 

through June 28, 2006. In all, approximately 7,200 individual ammonia and associated 

measurements were attempted in the course of this project. One of the primary outcomes of this 

sampling was the disclosure that high concentrations of ammonia are occurring in the northern 

and central CENRAP regions with a considerable regularity. It seems likely that these are due to 

the agricultural sources that have been documented as emitters of ammonia, including animal 

raising and fertilizer application.5 

 

5

 Caughey, Mike, David Gay, and Clyde Sweet. CENRAP Project Report: Monitoring Ambient Ammonia and 

Related Compounds in the Midwest 2003-2006. Illinois State Water Survey. (Champaign, IL): August 31, 2006. A 

copy of the report is available from David A. Gay, Associate Research Scientist, Illinois State Water Survey, 

University of Illinois, 217-244-0462. 
34

7.0 EMISSIONS INVENTORY 

7.1 2002 AND 2018 EMISSIONS INVENTORY SUMMARY

As specified in the EPA guidance document, Emissions Inventory Guidance for Implementation 

of Ozone and Particulate Matter National Ambient Air Quality Standards (NAAQS) and 

Regional Haze Regulations (August 2005), the regional haze emissions inventory includes 

carbon monoxide (CO), nitrogen oxides (NOx), sulfur dioxide (SO2), volatile organic compounds 

(VOCs), fine particulate (PM2.5), coarse particulate (PM10), and ammonia (NH3). Missouri used 

the CENRAP Base G emissions inventory for both the baseline year of 2002 and future year of 

2018. Tables 7.1 and 7.2 summarize the Missouri 2002 and 2018 inventories, respectively. 

Tables H.1-8 in Appendix H include the complete 2002 and 2018 emissions inventory for 

Missouri. 

Table 7.1: 2002 Missouri Emissions Inventory Summary 

Source Sector NOX (TPY*) SO2 (TPY) PM10 (TPY) PM2.5 (TPY) CO (TPY) VOC (TPY) NH3 (TPY)

Point EGU** 145,437.9 272,128.1 4,093.2 2,523.2 11,357.0 1,796.4 19.2

Point NEGU*** 36,143.8 97,117.0 15,092.2 7,045.3 107,756.3 38,473.6 6,233.9

Area 31,337.8 48,510.9 29,975.9 26,385.8 135,292.9 204,940.2 2,276.7

Offroad Mobile 99,305.6 9,350.5 13,063.5 11,985.3 754,272.8 141,183.3 73.9

Onroad Mobile 189,852.3 5,353.5 4,486.6 3,297.4 1,585,277.1 97,245.6 5,993.5

Fire 3,539.6 936.2 12,407.2 10,642.3 151,389.6 12,867.9 1,447.2

Ag and Soil Ammonia 0.0 0.0 0.0 0.0 0.0 0.0 152,904.1

Fugitive Dust 0.0 0.0 95,240.0 19,006.9 0.0 0.0 0.0

Road Dust 0.0 0.0 367,390.3 55,011.6 0.0 0.0 0.0

Biogenics 22,518.6 0.0 0.0 0.0 134,123.4 1,428,260.0 0.0

Totals 528,135.5 433,396.3 541,748.9 135,897.8 2,879,469.2 1,924,767.1 168,948.5

Table 7.2: 2018 Missouri Emissions Inventory Summary 

Source Sector NOX (TPY) SO2 (TPY) PM10 (TPY) PM2.5 (TPY) CO (TPY) VOC (TPY) NH3 (TPY)

Point EGU 84,619.8 289,330.1 18,958.2 17,036.6 15,752.7 2,080.5 874.4

Point NEGU 49,290.8 66,731.1 23,598.8 10,171.7 184,350.9 54,908.6 8,600.2

Area 35,212.8 49,726.1 29,193.0 25,528.5 120,114.9 265,737.4 4,411.8

Offroad Mobile 59,624.9 565.2 8,371.3 7,675.0 739,932.9 72,794.1 84.8

Onroad Mobile 50,860.9 797.4 1,415.5 1,415.5 895,481.6 39,672.3 8,316.0

Fire 3,539.6 936.2 12,407.2 10,642.3 151,389.6 12,867.9 1,447.2

Ag and Soil Ammonia 0.0 0.0 0.0 0.0 0.0 0.0 182,451.5

Fugitive Dust 0.0 0.0 106,045.3 21,147.2 0.0 0.0 0.0

Road Dust 0.0 0.0 313,576.4 46,957.9 0.0 0.0 0.0

Biogenics 22,518.6 0.0 0.0 0.0 134,123.4 1,428,260.0 0.0

TOTALS 305,667.4 408,086.1 513,565.8 140,574.6 2,241,146.0 1,876,320.7 206,185.9

* Tons Per Year 

** Electric Generating Unit 

*** Non-Electric Generating Unit
35

7.2 OVERVIEW OF EMISSIONS INVENTORY DEVELOPMENT

7.2.1 Point Sources 

The 2002 point source inventory is based on information reported by facilities on Emission 

Inventory Questionnaires (EIQs). The 2002 EIQ data collection process was conducted by the 

department’s Air Pollution Control Program and the local air pollution agencies of St. Louis 

County and the City of St. Louis. As the coordinating agency for point source inventory 

development, the department’s Air Pollution Control Program performed the overall qualityassurance procedures and submitted the data to EPA’s 2002 National Emissions Inventory (NEI) 

to meet the requirements of the CERR. 

Following submission of the Missouri point source inventory to the 2002 NEI, additional quality 

assurance, and revision of the data was completed through the CENRAP process. E. H. Pechan 

& Associates (Pechan), through a contract with CENRAP, obtained the Missouri point source 

inventory and worked with the department’s Air Pollution Control Program to make corrections 

where needed. In particular, an error that resulted in the double counting of emissions from a 

number of emission units was corrected. The problem affected VOC emissions only. For 

example, for the Chrysler-North facility (291890231), emission unit number 20949, which 

emitted a total of 112 tons/year (about 0.3 tons/day) VOC in 2002, was associated with stack 

numbers 44387 and 44388. Instead of being proportioned between the two stacks, the total 

amount of 112 tons/year was linked to each stack, which doubled the emissions. In all, this 

problem resulted in overstating VOC emissions in the St. Louis nonattainment area by a total of 

751 tons/year (roughly 2 tons/day). Other revisions included corrections to facility coordinates 

and stack parameters. Pechan also converted the point source inventory to the Sparse Matrix 

Operator Kernel Emissions/Inventory Data Analyzer (SMOKE/IDA) format. Pechan’s work is 

described in detail in the two documents included in Appendix H: The Consolidation of 

Emissions Inventories (April 28, 2005) and Refinement of CENRAP’s 2002 Emissions 

Inventories (August 31, 2005). 

The 2018 point source emissions inventory was prepared by CENRAP. For non-EGUs, the 2002 

emissions were projected to 2018 by applying growth and control factors using the SMOKE 
36

model. The growth and control factors were prepared by Pechan and are documented in the 

following report in Appendix H.4: Development of Growth and Control Inputs for CENRAP 

2018 Emissions Draft Technical Support Document (May 2005). The control factors for nonEGU point sources account for Maximum Achievable Control Technology (MACT) standards 

and the NOX SIP Call for industrial boilers. In addition, the newly permitted Holcim cement kiln 

in Ste. Genevieve County was added to the 2018 non-EGU point inventory. 

The Integrated Planning Model (IPM) version 2.1.9 model output for 2018 was used for 2018 

EGU point source emissions. The SMOKE IDA formatted version of the 2018 Integrated 

Planning Model (IPM) 2.1.9 file was prepared by Pechan for CENRAP. See the Pechan report, 

Refinement of CENRAP’s 2002 Emissions Inventories (August 31, 2005), in Appendix H.3 for 

more information. The proprietary IPM model has been used by the EPA to simulate electrical 

power generation and electrical power distribution scenarios based upon “least-cost” 

assumptions for future years and, simultaneously, generate estimates of pollutant emissions 

associated with these scenarios. The IPM run was conducted by ICF under contract to the RPOs. 

This run corresponds with the “VISTASII_PC_1f” modeling run. This run specifically 

addressed the emission reductions to be realized through implementation of CAIR assuming all 

states participate in the EPA’s trading program, Acid Rain Program (Title IV – Phases I and II), 

NOX SIP Call, and state and local regulations, while incorporating unit-level updates provided by 

power company stakeholders. 

The University of California-Riverside (UCR) ran the SMOKE model for 2018 point source 

emissions. The edited IPM file for EGUs was processed in SMOKE without adjustments. The 

growth and control factors for non-EGUs were applied using the SMOKE model. The technical 

support document in Appendix F describes UCR’s work on the 2018 point source inventory. 

7.2.2 Area Sources 

The 2002 area source inventory includes emissions estimates prepared by the department’s Air 

Pollution Control Program and CENRAP, with remaining gaps filled in with data from the NEI. 

Table H.9 in Appendix H.1 lists the source of the emissions estimates for each SCC in the base 

year area source inventory. For the categories developed by the department’s Air Pollution 
37

Control Program, the data and methods used are described in the document Missouri Statewide 

Estimates for the 2002 National Emissions Inventory (NEI): Area Sources (January 8, 2007) in 

Appendix H.5. The data and methods used to develop the prescribed burning, agricultural dust, 

and soil agricultural ammonia inventories for CENRAP can be found in the following reports 

prepared by Sonoma Technology in Appendix H: Research and Development of Planned 

Burning Emission Inventories for the Central States Regional Air Planning Association (July 30, 

2004), Emission Inventory Development for Mobile Sources and Agricultural Dust Sources for 

the Central States (October 28, 2004), and Research and Development of Ammonia Emission 

Inventories for the Central States Regional Air Planning Association (October 30, 2003). 

Documentation of EPA’s methods for the NEI may be found on EPA’s Clearinghouse for 

Inventories and Emission Factors (CHIEF) website at 

http://www.epa.gov/ttn/chief/net/2002inventory.html. 

In a contract with CENRAP, Pechan consolidated the area source data from the various sources, 

conducted additional quality assurance, and worked with the department’s Air Pollution Control 

Program to make revisions where needed. In particular, corrections were made to a doublecounting error of industrial surface coating VOC emissions. Pechan also converted the area 

source inventory to the SMOKE/IDA format. Pechan’s work is described in detail in two 

documents included in Appendix H: The Consolidation of Emissions Inventories (April 28, 

2005) and Refinement of CENRAP’s 2002 Emissions Inventories (August 31, 2005). 

To prepare the area inventories for modeling, UCR made several modifications to the IDA files 

by removing selected sources either to model them as separate source categories or to omit them 

from simulations completely. Fugitive and road dust sources were extracted from all stationaryarea inventories and adjusted by transport factors following Methodology to Estimate the 

Transportable Fraction (TF) of Fugitive Dust Emissions for Regional and Urban Scale Air 

Quality Analyses (Pace 2005). 

The 2018 area source emissions inventory was based on data provided by CENRAP states. Area 

source growth and control factors were prepared by Pechan and are documented in the following 

report in Appendix H.5: Development of Growth and Control Inputs for CENRAP 2018 
38

Emissions Draft Technical Support Document (May 2005). The control factors reflect New 

Source Performance Standards (NSPS) for residential wood combustion and Stage II vapor 

recovery controls, including onboard vapor recovery. 

UCR ran the SMOKE model for the 2018 area source emissions. The growth and control factors 

for area sources were applied within SMOKE. The technical support document in Appendix F 

describes UCR’s work on the 2018 area source inventory. Windblown dust from nonagricultural land use categories and fire emissions were held constant from 2002 to 2018. 

7.2.3 Offroad Mobile Sources 

The 2002 offroad mobile source includes emissions estimates prepared by the department’s Air 

Pollution Control Program and CENRAP, with remaining gaps filled in with EPA NEI data. 

Table H.10 in Appendix H.1 lists the source of the emissions estimates for each SCC in the base 

year offroad mobile inventory. The majority of the offroad mobile inventory was developed by 

Sonoma Technology under a contract with CENRAP. The methods and data used by Sonoma 

are described in the report Emissions Inventory Development for Mobile Sources and 

Agricultural Dust Sources for the Central States (October 28, 2004) in Appendix H.7. 

Information on the NONROAD model is at http://www.epa.gov/otaq/nonrdmdl.htm. 

Pechan, under a contract with CENRAP, consolidated the offroad mobile source inventories 

from the various data sources, quality-assured the data, worked with the department’s Air 

Pollution Control Program to make corrections where needed, and created SMOKE/IDAformatted files. In particular, Pechan made corrections to the fuel oxygenate content used in the 

NONROAD model. Pechan’s work is described in detail in the two documents included in 

Appendix H: The Consolidation of Emissions Inventories (April 28, 2005) and Refinement of 

CENRAP’s 2002 Emissions Inventories (August 31, 2005). 

The 2018 offroad mobile inventory was based on inputs from CENRAP states. Growth and 

control factors for locomotives, aircraft, and commercial marine vessels were prepared by 

Pechan. The control factors accounted for federal standards for commercial marine vessels and 

locomotives. For the remaining offroad mobile categories, Pechan ran the EPA’s 
39

NONROAD2004 model for 2018. EPA’s NONROAD2004 model accounts for growth in 

equipment populations and incorporates the effects of most final federal standards, including the 

Tier 4 diesel engine standards and the exhaust emission standards for large spark-ignition 

engines, diesel marine, and land-based recreational engines. Pechan’s methods are described in 

greater detail in the following report in Appendix H.4: Development of Growth and Control 

Inputs for CENRAP 2018 Emissions Draft Technical Support Document (May 2005). 

UCR and applied the growth and control factors to non-NONROAD categories using the 

SMOKE model. In addition, UCR processed NONROAD-model categories in SMOKE without 

adjustments. The technical support document in Appendix F describes UCR’s work on the 2018 

offroad inventory 

7.2.4 Onroad Mobile Sources 

The department’s Air Pollution Control Program and CENRAP, with contractor support, 

developed the 2002 and 2018 onroad mobile source emissions inventories. Sonoma Technology 

provided 2002 VMT data and MOBILE6 input files for all counties in the CENRAP region. 

MOBILE6 input files were provided only for the months of January and July for 2002. The 

methods and data used by Sonoma are described in the report Emissions Inventory Development 

for Mobile Sources and Agricultural Dust Sources for the Central States (October 28, 2004) in 

Appendix H.7. UCR prepared MOBILE6 input files for the remaining months of 2002 and 

processed the 2002 mobile emissions using the MOBILE6 model within the SMOKE 

framework. 

Pechan prepared the VMT and MOBILE6 inputs for the 2018 onroad mobile source emissions 

inventory. The VMT growth factors and MOBILE6 input files were provided in SMOKE 

format. The MOBILE6 input files incorporated state/local control program information, 

including Reformulated Gasoline and the inspection and maintenance program in the St. Louis 

nonattainment area and low Reid vapor pressure (RVP) gasoline in the Kansas City maintenance 

area. For each county or group of counties modeled, two SMOKE-formatted MOBILE6 files 

were prepared: one representing July conditions and one representing January conditions. 

Pechan’s methods are described in greater detail in the following report in Appendix H.4: 
40

Development of Growth and Control Inputs for CENRAP 2018 Emissions Draft Technical 

Support Document (May 2005). 

UCR prepared MOBILE6 input files for the remaining months of 2018 and processed the 2018 

onroad mobile emissions by running the MOBILE6 model within the SMOKE framework. The 

SMOKE model applies the VMT growth factors. The MOBILE6 model accounts for federal 

motor vehicle controls, including light-duty motor vehicle engine standards and low-sulfur 

gasoline, and the federal heavy-duty diesel engine standards and low-sulfur diesel. The technical 

support document in Appendix F describes UCR’s onroad mobile emissions inventory 

processing. 

7.2.5 Biogenic Emissions 

UCR generated biogenic emissions by running the BEIS3 model within the SMOKE framework. 

BEIS3 is a system integrated into SMOKE for deriving emissions estimates of biogenic gasphase pollutants from land use information, emissions factors for different plant species, and 

hourly, gridded meteorology data. Biogenic emissions were held constant from 2002 to 2018. 

The technical support document in Appendix F describes the development of the biogenic 

emissions inventory. 

7.3 PERIODIC UPDATES OF EMISSIONS INVENTORIES

Recognizing the importance of maintaining current, valid emissions information, the 

department’s Air Pollution Control Program commits to periodically updating the Missouri 

statewide emissions inventories. The point source inventories will be updated on an annual basis, 

and the area, onroad mobile, and offroad mobile inventories will be updated every three years. 

The three-year updates will begin with the inventory for calendar year 2008, and follow with 

2011, 2014, and so on, consistent with EPA’s emissions inventory reporting requirements. 

In addition to completing regular updates of Missouri’s emissions inventory, the Air Pollution 

Control Program commits to periodically reviewing emissions information for other states and 

future-year emissions projections and making adjustments where needed. This effort will consist 

of reviewing and updating any technical data and assumptions regarding emissions growth rates, 
41

implementation of emissions controls, and geographic distribution of emissions. The periodic 

reviews will be coordinated with other states and consultation partners and will be conducted in 

conjunction with the five-year progress reports discussed in section 2.6. 
42

8.0 MODELING ASSESSMENT 

8.1 MODELING REQUIREMENTS

40 CFR 51, Appendix W provides modeling guidelines for conducting regional-scale modeling 

for particulate matter and visibility. The EPA recommends the use of one of the three following 

models to simulate pollutants impairing visibility: Community Multiscale Air Quality (CMAQ), 

Comprehensive Air quality Model with extensions (CAMx), and Regional Modeling System for 

Aerosols and Deposition (REMSAD). CENRAP contractors performed regional modeling using 

CMAQ and CAMx. 

The CMAQ Model is an Eulerian model that simulates the atmospheric and surface processes 

affecting the transport, transformation and deposition of air pollutants and their precursors. An 

Eulerian model computes the numerical solution of partial differential equations of plumes on a 

fixed grid, while other models may lose accuracy or need regridding as the plumes expand. 

CAMx is a computer modeling system for the integrated assessment of photochemical and 

particulate air pollution. CAMx incorporates all of the technical attributes demanded of state-ofthe-art photochemical grid models, including two-way grid nesting, a subgrid-scale Plume-inGrid module to treat the early dispersion and chemistry of point source NOX plumes, and a fast 

chemistry solver. 

In the July 1, 1999 publication of the Regional Haze Rule in the Federal Register, EPA defined 

the uses of regional modeling as follows: 

 Analyses and determination of the extent of emissions reductions needed from individual 

states 

 Analyses and determination of emissions needed to meet the progress goal for the Class I 

area 

 Analyses to support conclusion that the Long-Term Strategy provides for reasonable 

progress 

 Analyses to calculate the resulting degree of visibility improvement that would be 

achieved at each Class I area 
43

 Analyses to compare visibility improvement between proposed control strategies 

8.2 MODEL INPUTS

8.2.1 Selection of Episodes 

The calendar year 2002 was selected for the base year for CENRAP regional haze annual 

modeling consistent with EPA guidance. The Technical Support Document provides additional 

information on the selection of 2002 as the base year for regional haze modeling and is found at 

Appendix F. 

8.2.2 Selection of Modeling Domain 

CENRAP conducted emissions and air quality modeling on the 36 km national RPO domain. 

This domain consists of a 148 by 112 array of 36 km by 36 km grid cells and covers the 

continental United States. The Technical Support Document provides additional information on 

the modeling domain and is found at Appendix F. 

8.2.3 Emission Inventories 

The emissions inventory includes VOC, NOX, CO, SO2, PM10, PM2.5, and NH3 emissions from 

all anthropogenic and biogenic sources. The emissions inventory information submitted by state, 

tribal, and local agencies to the 2002 NEI formed the basis of the 2002 CENRAP emissions 

inventory. The NEI data was supplemented with non-point source emissions inventories 

developed for CENRAP by Sonoma Technology. These CENRAP-specific inventories 

addressed agricultural and prescribed burning, onroad and offroad mobile sources, agricultural 

tilling and livestock dust, and agricultural ammonia. In addition, Pechan assisted CENRAP by 

quality-assuring the emissions inventory and preparing day- and hour-specific emissions for 

EGUs based on Continuous Emissions Monitor (CEM) data for the model performance 

evaluation. 

Emissions inputs for the air quality model were prepared using the SMOKE emissions modeling 

system. The CENRAP modeling emissions inventory consists of several distinct datasets: the 

2002 base case for model performance evaluation, 2002 typical, 2018 base case, and the 2018 

control strategy scenario. Its spatial extent is the RPO 36 km modeling domain, which covers 
44

the continental U.S. plus portions of Canada and Mexico. The inventory was refined through 

several rounds of CENRAP workgroup review and revision, beginning with the initial Base A 

version and culminating in the Base G inventory. The Technical Support Document provides the 

methodologies for the SMOKE emissions processing and is found at Appendix F. A summary of 

the development of the emissions inventory can be found in Chapter 7. 

8.2.4 Meteorology 

The Fifth-Generation NCAR / Penn State Mesoscale Model (MM5) is the latest in a series that 

developed from a mesoscale model used by Anthes at Penn State in the early 70's that was later 

documented by Anthes and Warner (1978). Since that time, it has undergone many changes 

designed to broaden its usage. These include (i) a multiple-nest capability, (ii) nonhydrostatic 

dynamics, which allows the model to be used at a few-kilometer scale, (iii) multitasking 

capability on shared- and distributed-memory machines, (iv) a four-dimensional dataassimilation capability, and (v) more physics options. The model (known as MM5) is supported 

by several auxiliary programs, which are referred to collectively as the MM5 modeling system. 

Since MM5 is a regional model, it requires an initial condition as well as a lateral boundary 

condition to run. To produce a lateral boundary condition for a model run, one needs gridded 

data to cover the entire time period that the model is integrated. The Technical Support 

Document provides the methodologies for this process and is found at Appendix F. 

8.3 MODEL PERFORMANCE EVALUATION

Model evaluations compared concentrations of various pollutants simulated by CMAQ and 

CAMx with observations from: 

 IMPROVE 

 Clean Air Status and Trends Network (CASTNet) 

 Speciated Trends Network (STN) 

 Aerometric Information Retrieval Systems (AIRS) 

 South Eastern Aerosol Research and Characterization (SEARCH) 

The CMAQ and CAMx models were evaluated against ambient measurements of PM species, 

gas-phase species and wet deposition. Numerous iterations of CMAQ and CAMx 2002 base 
45

case simulations and model performance evaluations were conducted during the course of the 

CENRAP modeling study, most of which have been posted on the CENRAP modeling website 

(http://pah.cert.ucr.edu/aqm/cenrap/cmaq.shtml) and presented in previous reports and 

presentations for CENRAP. In general, the model performance of the CMAQ and CAMx 

models for SO4 and elemental carbon (EC) was good. Model performance for nitrate (NO3) was 

variable, with a summer underestimation and winter overestimation bias. Performance for OMC 

was also variable, with the inclusion of the Secondary Organic Aerosol Modules enhancement in 

CMAQ Version 4.5 greatly improving the CMAQ summer OMC model performance. Model 

performance for Soil and coarse mass was generally poor. Part of the poor performance for soil 

and coarse mass is believed to be due to measurement-model incommensurability whereby the 

IMPROVE measured values are due in part to local fugitive dust sources that are not captured in 

the model’s emission inputs and 36 km grid resolution. Detailed information on the model 

performance evaluations is found in the Technical Support Document in Appendix F. 

8.4 BASE G MODEL SIMULATIONS

8.4.1 2018 Base G visibility projections 

The 2018 Base G modeling run reflects emissions growth and “on the books” controls, which are 

state and federal controls that will be implemented between the 2002 base year and the 2018 

future year. The 2018 emissions for EGUs were based on simulations of the IPM that took into 

account the effects of the CAIR trading program. In addition, reductions anticipated from BART 

controls for EGUs in Oklahoma, Arkansas, Kansas, and Nebraska were included. Emissions for 

onroad and offroad mobile sources were based on activity growth and emissions factors from the 

EPA MOBILE6 and NONROAD models, respectively, which reflected emissions reductions 

from the Tier 2 and Tier 4 mobile source rules. Area sources and non-EGU point sources were 

grown to 2018 levels. 

The two important regional haze metrics are the average visibility for the worst 20 percent and 

best 20 percent days from the 2000-2004 five-year baseline period. The results from the 2002 

and 2018 CMAQ and CAMx simulations were used in a relative sense to scale observed PM 

concentrations from the 2000-2004 baseline to 2018 levels from which 2018 visibility estimates 

were obtained. The CENRAP 2018 visibility conditions were calculated following EPA default 
46

visibility projection procedures and are labeled “Method 1 Prediction” in Figures 8.1 and 8.2. 

The steps involved in the visibility calculations are described below: 

1. For each Class I area and each monitored day, daily visibility based on IMPROVE 

data and the new IMPROVE equation was ranked for the five-year baseline period 

(2000-2004) to identify the worst 20 percent and best 20 percent visibility days for 

each year in the baseline period. 

2. The CMAQ air quality model was used to simulate the base year (for CENRAP the 

2002 annual period was simulated) and a future-year (2018). The resulting 

information was used to develop Class I area-specific relative reduction factors 

(RRFs) for each of the six components of light extinction in the IMPROVE equation 

(SO4, NO3, EC, OMC, Soil and CM). 

3. The RRFs were multiplied by the measured 24-hour PM concentration for each day 

from the worst and best 20 percent days in each year from the five-year baseline 

period to obtain projected future-year 24-hour PM concentrations for the worst and 

best 20 percent days. 

4. The future-year (2018) daily extinction was computed using the new IMPROVE 

equation and the projected PM concentrations for each of the worst and best 20 

percent days in the five-year baseline from step 3. 

5. For each of the worst and best 20 percent days within each year of the five-year 

baseline, the future-year daily extinction was converted to deciview. The daily 

deciview values were averaged within each of the five years separately to obtain five 

years (or as many years with valid data in the 2000-2004 baseline) of average 

deciview visibility for the worst and best 20 percent days. 

6. The five years of deciview visibility were averaged to obtain the 2018 estimated 

visibility. 

The 2018 visibility projections for the worst 20 percent days and best 20 percent days are 

compared against a 2018 point on the Uniform Rate of Progress (URP) glidepath or the “2018 

URP point.” The 2018 URP point is obtained by constructing a linear visibility glidepath in 

deciviews from the observed 2000-2004 Baseline for the worst 20 percent days to the 2064 
47

Natural Conditions. The 2018 URP point is where the linear glidepath crosses the year 2018. 

Figures 8.1 and 8.2 present the 2018 visibility projections for Hercules Glades and Mingo. As 

seen in these figures, the 2018 visibility projections at both the Hercules Glades and Mingo Class 

I areas meet the 2018 point on the URP glidepath for the worst visibility days and exhibit no 

degradation on the best visibility days. For the worst 20 percent days, the 2018 projection for 

Hercules Glades is 23.06 dv, compared to the URP point of 23.14 dv. The 2018 projection for 

Mingo is 23.71 dv, as compared to the URP point of 24.37 dv. 

Additional information on the CENRAP visibility projections based on the Base G modeling 

results is summarized in 4.4. of the Technical Support Document (TSD), which indicates that 

Appendix D of the TSD provides details for each Class I area in the CENRAP region using the 

new IMPROVE equation. 
48

Figure 8.1a: 2018 Visibility Projections and 2018 URP Glidepaths in deciview for Hercules Glades, Missouri, 

and Worst 20% days using 2002/2018 Base G CMAQ 36 km modeling results.

Uniform Rate of Reasonable Progress Glide Path

Hercules-Glades Wilderness - Best 20% Days

12.84 12.84 12.84 12.84 12.84 12.84 12.84 12.84

11.95

0

2

4

6

8

10

12

14

16

2000 2004 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 2048 2052 2056 2060 2064

Year

Haziness Index (Deciviews)

Glide Path Natural Condition (Best Days) Observation Method 1 Prediction

Figure 8.1b: 2018 Visibility Projections and 2018 URP Glidepaths in deciview for Hercules Glades, Missouri, 

and Best 20% days using 2002/2018 Base G CMAQ 36 km modeling results. 

Uniform Rate of Reasonable Progress Glide Path

Hercules-Glades Wilderness – Worst 20% Days

26.75

25.72

23.14

20.57

17.99

15.42

12.84

11.30

23.06

0

5

10

15

20

25

30

2000 2004 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 2048 2052 2056 2060 2064

Year

Haziness Index (Deciviews)

Glide Path Natural Condition (Worst Days) Observation Method 1 Prediction
49

Uniform Rate of Reasonable Progress Glide Path

Mingo – Worst 20% Days

28.02 26.98

24.37

21.77

19.17

16.56

13.96

12.40

23.71

0

5

10

15

20

25

30

35

2000 2004 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 2048 2052 2056 2060 2064

Year

Haziness Index (Deciviews)

Glide Path Natural Condition (Worst Days) Observation Method 1 Prediction

Figure 8.2a: 2018 Visibility Projections and 2018 URP Glidepaths in deciview for Mingo, Missouri, and 

Worst 20% days using 2002/2018 Base G CMAQ 36 km modeling results. 

Uniform Rate of Reasonable Progress Glide Path

Mingo - Best 20% Days

13.76 13.76 13.76 13.76 13.76 13.76 13.76 13.76

12.84

0

2

4

6

8

10

12

14

16

2000 2004 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 2048 2052 2056 2060 2064

Year

Haziness Index (Deciviews)

Glide Path Natural Condition (Best Days) Observation Method 1 Prediction

Figure 8.2b: 2018 Visibility Projections and 2018 URP Glidepaths in deciview for Mingo, Missouri, and Best 

20% days using 2002/2018 Base G CMAQ 36 km modeling results. 
50

8.4.2 Other RPO’s visibility projections 

The 2018 visibility projections for the two Missouri Class I areas are also available from the 

VISTAS and MRPO modeling. At Hercules Glades, the three RPOs’ 2018 visibility projections 

are in close agreement with each other, estimated to achieve 102 percent, 101 percent and 96 

percent of the 2018 URP point. The CENRAP and VISTAS 2018 visibility projections are also 

very close at Mingo, 118 percent and 114 percent, respectively. However, the MRPO 2018 

visibility projections are approximately 15 percentage points lower than the CENRAP and 

VISTAS projections at Mingo. The reasons why the MRPO 2018 visibility projections are less 

optimistic than CENRAP and VISTAS are unclear. The discrepancy could be due to the use of 

different emissions inventories. CENRAP's Base G inventory included IPM 2.1.9 results for 

2018 EGU emissions that had been quality-assured and edited by CENRAP and VISTAS states 

and stakeholders, while MRPO's latest modeling inventory used IPM 3.0 results that did not 

include edits from VISTAS or most of the CENRAP states. The department’s Air Pollution 

Control Program concluded that CENRAP projections for Mingo and Hercules Glades should be 

more accurate due to a better emissions inventory for our states. Additional analysis including 

the IPM 3.0 results with states’ review will be considered during the five-year review period. 
51

9.0 BEST AVAILABLE RETROFIT TECHNOLOGY (BART) 

9.1 BART REQUIREMENTS

The EPA’s 1999 Regional Haze Rule singles out certain older emission sources that have not 

been regulated under other provisions of the Clean Air Act for additional controls. Older sources 

that contribute to visibility impairment in Class I areas are required to implement BART or an 

emissions trading or other alternative program that will achieve greater reasonable progress than 

would be achieved through the installation and operation of BART. On July 6, 2005, EPA 

published a revised final rule, including Appendix Y to 40 CFR 51 “Guidelines for BART 

Determinations Under the Regional Haze Rule” that provides direction to states on determining 

which of these older sources may need to install BART and how to determine BART. 

Based on comments received from EPA Region VII, sources originally not included in the 

BART air quality review were re-examined. Some additional sources were found to be BART 

eligible and were evaluated in the same fashion as the original sources. Upon completion of the 

BART air quality screen and draft refined modeling analyses; the State of Missouri has found 

one source that is subject to BART. This source (Holcim – Clarksville) has signed a consent 

agreement with emission limits that represent BART for the applicable source. This agreement 

with the department is included in this submittal as the enforceable mechanism for the necessary 

emission control requirements. No other sources were found to be subject to BART and, 

therefore, implementation of an emissions trading program, other emission controls or other 

alternative measure in place of BART are not necessary. 

9.2 BART – ELIGIBLE SOURCES IN STATE OF MISSOURI

The facilities with BART-eligible units in the State of Missouri are shown in Table 9.1 

(including the newly identified sources). A detailed description of each BART-eligible emission 

unit is included in Appendix I. 
52

Table 9.1: Facilities with BART-eligible Units in the State of Missouri 

BART Source Category 

Name 

SIC 

Code Facility ID Facility Name BART-Eligible Emission Units 

Fossil-fuel fired steam 

electric plants of more 

than 250 MMBTU (1)* 

4911 29-071-0003 Ameren – Labadie Boiler 1 – B1, Boiler 2 – B2, Boiler 3 

– B3, and Boiler 4 – B4 

(1)* 4911 29-183-0001 Ameren – Sioux Boiler 1 – B1 and Boiler 2 – B2 

(1)* 4911 29-099-0016 Ameren – Rush Island Boiler 1 – B1 and Boiler 2 – B2 

(1)* 4911 29-095-0031 Aquila – Sibley Boiler 3 – 5C 

(1)* 4911 29-143-0004 Associated Electric – New 

Madrid 

Boiler 1 – EP-01 and Boiler 2 – EP 

– 02 

(1)* 4911 29-077-0039 City Utilities Springfield - 

Southwest Boiler 1 – E09 

(1)* 4911 29-077-0005 City Utilities Springfield – 

James River 

Utility Boiler #4 – E07 and Utility 

Boiler #5 – E08 

(1)* 4911 29-097-0001 Empire District Electric – 

Asbury Boiler – 7 

(1)* 4911 29-083-0001 Kansas City Power and 

Light – Montrose Boiler Unit 3 – EP08 

(1)* 4911 29-021-0004 Aquila – Lake Road Boiler 6 – EP06 

(1)* 4911 29-175-0001 Associated Electric – 

Thomas Hill 

Boiler 1 - EP-01 and Boiler 2 – EP02 

(1) 4911 29-095-0021 Trigen – Kansas City Boiler 1A 

(1) 4911 29-019-0002 City of Columbia 

Municipal Power Plant Boiler #7 - EP02 

(1) 4911 29-195-0010 Marshall Municipal Utilities Coal-Fired Boiler - EP05 

(1) 4911 29-095-0050 Independence Power and 

Light – Blue Valley Boiler #3 – EP05 

Portland cement plants 

(4) 3241 29-099-0002 RC Cement 4-K-02 (Kiln) 

(4) 3241 29-173-0001 Continental Cement KP01 (Kiln) 

(4) 3241 29-163-0001 Holcim - Clarksville Kiln – EP14 and a variety of 

supporting units 

Primary aluminum ore 

reduction plants (7) 3334 29-143-0008 Noranda Aluminum 

Potlines 1 & 2 – EP-59,60,& 61, 

Carbon Bake 1 and 2 Stacks – EP 

98 & 99, and a variety of supporting 

units** 

Hydrofluoric, sulfuric, and 

nitric acid plants (10) 2873 29-163-0031 Dyno Nobel – Lomo Plant Ammonia Oxidation Process – E01 

Lime plants (12) 3274 29-186-0001 Mississippi Lime Peerless Rotary Kilns 3,4,5&6 – EP68-71 

Primary lead smelters 

(17) 3339 29-099-0003 Doe Run – Herculaneum Blast Furnace – EP059 

(17) 3339 29-093-0008 Doe Run – Glover Sinter Plant - EP-01 and Other 

Units at the facility 

Secondary metal 

production facilities (20) 3341 29-087-0001 Exide Technologies Main Stack – EP01 

(20) 3339 29-093-0009 Doe Run – Buick Main Stack – EP08 

Chemical Process Plants 

(21) 2879 29-127-0001 BASF Corporation 

PR08 – HNO3 Storage Tank, 

PR53/54 Incinerators, TC01 

Incinerator, UTIL07 – 2 Gas-fired 

boilers

Fossil-fuel boilers >250 

MMBTUs per hour (22) 4911 29-019-0004 University of Missouri – Columbia Boiler 10 

*BART-eligible EGU units included in the CAIR assumed to be BART for SO2 and NOX

** Other supporting units listed in facility summary later in this section 

Italics means BART-eligible source identified after EPA comments 
53

The BART-eligible sources were identified using the methodology in the Guidelines for BART 

Determinations under the Regional Haze Rules or “Guidelines” (40 CFR 51, Appendix Y). For 

an emission unit source to be identified as BART-eligible, the State of Missouri used these 

criteria from the Guidelines: 

 One or more emissions units at the facility fit within one of the 26 categories listed in the 

Guidelines; 

 The emission unit(s) were in existence on August 7, 1977 and began operation at some 

point on or after August 7, 1962; and 

 The limited potential emissions from all emission units identified in the previous two 

bullets emission units were greater than 250 tons or more per year of any of these 

visibility-impairing pollutants: SO2, NOX, and PM10. 

The Guidelines recommend addressing these visibility-impairing pollutants: SO2, NOX, and 

particulate matter. The State of Missouri addressed these three pollutants and used particulate 

matter less than 10 microns in diameter (PM10) as an indicator for particulate matter to identify 

BART-eligible units, as the Guidelines suggest. Consistent with the Guidelines, the State of 

Missouri did not evaluate emissions of VOCs and ammonia in BART determinations for these 

reasons: 

1) the majority of VOC emissions in Missouri are biogenic in nature and specifically the 

areas near Mingo and Hercules Glades are very rich in biogenic emissions (limited 

ability to reduce organic concentrations at the Class I areas), 

2) the largest areas of anthropogenic VOC emissions in Missouri exist in the 

metropolitan areas (St. Louis and Kansas City) where VOC emission control has been 

undertaken to address ozone attainment issues (meaning large VOC sources have 

already been controlled), 

3) the other category that would have substantial, uncontrolled VOC emissions is 

charcoal kilns, the department required existing charcoal kilns to install afterburners 

or shutdown noncompliant kilns as a result of 10 CSR 10-6.330, 

4) the overall ammonia inventory is very uncertain and the amount of anthropogenic 

emissions at the sources that were BART-eligible was relatively small, and 
54

5) No additional sources were identified that had greater than 250 tons per year 

ammonia and required a subsequent BART analysis. 

The State of Missouri identified potentially BART-eligible source by reviewing the emission 

inventory database and extracting data for facilities within the 26 categories identified. A survey 

was conducted for the facilities within this group asking for large source identification and the 

timing of the installation and operation of those sources. The sources listed in Table 9.1 have 

been identified as sources that meet the criteria for inclusion as BART-eligible sources. Beyond 

the three primary visibility-impairing pollutants (SO2, NOX, and PM10), the sources were also 

asked to identify ammonia and VOC emissions. The survey and resultant tabular response 

information are contained in Appendix J and Appendix I, respectively. 

9.3 DETERMINATION OF SOURCES SUBJECT TO BART 

Upon completion of the survey, the BART-eligible sources were divided into four distinct 

groups: (1) electric generating units participating in the CAIR trading program, (2) sources that 

have final new source review (construction) permits requiring a BART-eligible unit “shutdown” 

or no current operating permit at the facility, (3) sources that have gone through a subsequent 

construction permitting exercise for units that would have been BART-eligible based on original 

installation date, and (4) all other units that underwent a screen-modeling evaluation to determine 

the visibility impact on the applicable Class I area(s). 

The first and fourth groups were evaluated initially using a screen-modeling technique for 

visibility impact. The first group (CAIR EGUs) was modeled collectively using all BARTeligible sources for only the PM impacts on the applicable Class I areas (NOTE: After EPA 

comment, two additional CAIR EGU facilities were discovered to be BART-eligible and 

additional analysis was performed). All the sources in the fourth group were modeled 

independently. The second group included some or all of the BART-eligible sources at four 

installations. River Cement, Doe Run – Glover, Continental Cement, and Mississippi Lime all 

had units that were part of a voluntary shutdown or being removed due a specific construction 

permit condition. To be clear, the Doe Run – Glover facility does not have a current operating 

permit for any of the BART-eligible units at the facility. The department sent a notice to the 
55

company on November 13, 2007, that detailed the termination of the operating permit for the 

BART-eligible units after a thirty-day period allowed for the company to provide additional 

information. This period expired on December 13, 2007, and the permit was closed out. 

Therefore, the pyro-process units at Glover can not restart without a new construction permit 

requiring Best Available Control Technology (BACT) evaluation for each. These BARTeligible units were not included in the modeling analyses and are shown in Table 9.2. During the 

public comment period, Mississippi Lime Company provided a comment that changed the units 

that were subject to the BART air quality screening evaluation. Mississippi Lime Company has 

provided a permit modification that includes the continued use of Peerless Rotary Kiln #4 (EP69) 

at the facility. The unit was originally subject to shutdown provisions in the applicable permit, 

but the updated information required a new evaluation of the facilities’ BART-eligible units. 

The other unit in the shutdown provision (PRK #3 – EP68) has been dismantled. 

Table 9.2: Units Removed from BART Consideration Due to Shutdown or Federal Permit 

Requiring Shutdown 

Facility/Facility ID Units Reason for Removal from BART Consideration 

Doe Run – Glover / 29-083-0008 Pyro-process units No operating permit 

RC Cement / 29-099-0002 4-K-02 Permit #122005-005 

Mississippi Lime / 29-186-0001 EP68 Permit #122002-007 

Continental Cement / 29-173-0001 KP01 Permit #072007-008 

The third category illustrates a source that has undergone a major source permitting exercise for 

the units that would have been BART-eligible based on installation date. Doe Run – Buick 

underwent a Prevention of Significant Deterioration (PSD) review for Permit #0989-003 and a 

subsequent review for Permit #012005-008. Each review found that the blast furnace units had 

installed Best Available Control Technology (BACT). 

The BART-eligible unit at Doe Run – Buick is the blast furnace (referenced as EP-08, Main 

Stack). Under the 2005 construction permit, the entire facility is limited to 3,400 tons per year of 

SO2 with vast majority coming from the blast furnace. The other emissions from this unit are 

very limited - NOx and PM emissions are less than 10 tons per year. Therefore, a BART 

evaluation of the source could be required for SO2 if impact predicted from visibility modeling 
56

exceeded the 0.5 deciview threshold at the nearby Mingo National Wildlife Refuge. However, 

the department did not conduct this visibility evaluation initially due to a 2005 Best Available 

Control Technology (BACT) review for blast furnace SO2 control. The department assumed that 

since a BACT finding was made for this unit in the recent past that a BART evaluation was 

unnecessary. However, EPA Region VII commented that this was not sufficient for a BART 

finding. 

Therefore, department staff reviewed the SO2 BACT finding for the blast furnace and found that 

three different technologies were considered: wet scrubbing, dry scrubbing, and de-sulfurization 

of feed materials. Dry scrubbing was eliminated as technically infeasible due to excess 

hazardous waste generation. Wet scrubbing of the exhaust gas in a packed tower scrubber was 

selected as the best available technical option for significant control. However, the capital cost 

of this type of unit was estimated to be $24,100,000 with an annualized system cost of 

$11,000,000. The cost per ton SO2 reduced was $3,537, which demonstrated that this alternative 

was cost-ineffective. The continued use of chemical de-sulfurization of the battery paste input to 

the smelting process at the Buick facility was determined to be BACT and resulted in the SO2

emission limit in the 2005 permit. The BART finding is equivalent to the BACT finding in this 

case due to the high cost of the wet scrubbing technology and the on-going benefit of the desulfurization process. In addition to this cost finding and to better understand the visibility 

impact of the BART-eligible unit, the department conducted a sensitivity analysis of the Doe 

Run Buick facility on the nearby Mingo Class I area. The results of this sensitivity are included 

below in the refined screening discussion under Section 9.3.7 – Doe Run Buick. 

Under the Guidelines, the State has these options regarding its BART-eligible sources: a) make 

BART determinations for all sources or b) consider exempting some sources from BART 

because they do not cause or contribute to visibility impairment in a Class I area. The State of 
57

Missouri has chosen option b. If a state chooses option b, then the Guidelines suggest three suboptions for determining that certain sources need not be subject to BART: 

(1) Individual source attribution approach (dispersion modeling). 

(2) Use of model plants to exempt sources with common characteristics. 

(3) Cumulative modeling to show that no sources in a state are subject to BART. 

The State of Missouri has chosen sub-options 1 and 3 above to notify sources that would be 

required to conduct refined analyses based on the results of the screening analyses discussed 

previously. The goal was to determine if these sources cause or contribute to visibility 

impairment using the CALPUFF model. As discussed previously, the CAIR-affected electric 

generating units were collectively modeled for PM emissions only due to the presumptive BART 

determination for NOX and SO2 emissions from these sources. The results of this evaluation are 

included in Table 9.3. Examples of CALPUFF/CALPOST modeling input files used for 

determining which facilities are subject to BART are included in Appendix K. The CALPOST 

files included are not universal for all the facilities modeled. The Noranda facility utilized 

speciation of the PM emissions to include both a coarse fraction and a fine fraction. In addition, 

the remaining facilities included the PM10 emissions component as fine particulate matter (PMF) 

in the CALPOST analyses, but were sometimes called PM10 or PMF depending on the individual 

screening analysis. 

The State of Missouri utilized two different methods for evaluation of visibility impacts: (1) 

Method 2 – modeled relative humidity factors are calculated for each hour/day of the modeling 

period and (2) Method 6 – an average relative humidity factor is applied for each Class 1 area 

being evaluated. Based on the analyses, it was determined that Method 2 provides more 

conservative results for visibility calculation. Since only Method 6 was required by the BART 

rulemaking, the use of Method 2 gives added confidence to the findings regarding sources that 

did not trigger refined modeling. Some or all of the following Class 1 areas were evaluated 

based on source location: Mingo, Hercules Glades, Upper Buffalo, and Mammoth Cave 

(Kentucky). The screening evaluation criterion was a maximum deciview impact of greater than 

0.5 deciview to require a refined analysis. Six sources were identified during the source-specific 

screening analyses and these sources were notified to provide refined CALPUFF modeling 
58

analyses and/or the department conducted the refined screening analyses. In accordance with the 

guidelines, a contribution threshold of 0.5 deciview (98th percentile) was used for determining 

which sources were subject to BART using the refined modeling approach. 

The results of the individual screening analyses for each source are included in Table 9.3. 

Table 9.3: CALPUFF/CALPOST Screening Results 

Facility Class I Area Maximum 

Method 2 Impact

Maximum 

Method 6 Impact Year 

CAIR EGUs Hercules Glades 0.400 0.363 2001 

CAIR EGUs Hercules Glades 0.197 0.185 2002 

CAIR EGUs Hercules Glades 0.204 0.242 2003 

CAIR EGUs Mingo 0.078 0.088 2001 

CAIR EGUs Mingo 0.056 0.060 2002 

CAIR EGUs Mingo 0.060 0.068 2003 

CAIR EGUs Upper Buffalo 0.134 0.127 2001 

CAIR EGUs Upper Buffalo 0.147 0.151 2002 

CAIR EGUs Upper Buffalo 0.094 0.093 2003 

Exide Hercules Glades 0.019 0.010 2001 

Exide Hercules Glades 0.055 0.024 2002 

Exide Hercules Glades 0.032 0.021 2003 

Exide Upper Buffalo 0.034 0.018 2001 

Exide Upper Buffalo 0.056 0.025 2002 

Exide Upper Buffalo 0.035 0.022 2003 

Trigen - KC Hercules Glades 0.393 0.189 2001 

Trigen - KC Hercules Glades 0.200 0.092 2002 

Trigen - KC Hercules Glades 0.142 0.056 2003 

Trigen - KC Upper Buffalo 0.321 0.146 2001 

Trigen - KC Upper Buffalo 0.138 0.061 2002 

Trigen - KC Upper Buffalo 0.129 0.071 2003 

Dyno Nobel Mingo 0.185 0.081 2001 

Dyno Nobel Mingo 0.206 0.093 2002 

Dyno Nobel Mingo 0.118 0.049 2003 

Mississippi Lime Mingo 0.271 0.172 2001 

Mississippi Lime Mingo 0.302 0.263 2002 

Mississippi Lime Mingo 0.194 0.099 2003 

Mississippi Lime (Rev) Mingo 0.385 0.246 2001 

Mississippi Lime (Rev) Mingo 0.434 0.367 2002 

Mississippi Lime (Rev) Mingo 0.288 0.136 2003 

Doe Run - Herc Mingo 0.399 0.356 2001 

Doe Run - Herc Mingo 0.487 0.228 2002 

Doe Run - Herc Mingo 0.231 0.211 2003 

Noranda Mingo 1.118 0.663 2001 

Noranda Mingo 1.555 0.893 2002 

Noranda Mingo 1.816 1.080 2003 

Noranda Hercules Glades 0.512 0.411 2001 

Noranda Hercules Glades 1.098 0.534 2002 

Noranda Hercules Glades 0.617 0.520 2003 

Noranda Upper Buffalo 0.499 0.425 2001 

Noranda Upper Buffalo 0.841 0.648 2002 

Noranda Upper Buffalo 0.853 0.533 2003 
59

Noranda Mammoth Cave 0.634 0.352 2001 

Noranda Mammoth Cave 1.197 0.654 2002 

Noranda Mammoth Cave 0.547 0.265 2003 

UMC* Mingo 1.042 0.617 2001 

UMC Mingo 2.857 1.618 2002 

UMC Mingo 1.012 0.512 2003 

UMC Hercules Glades 0.996 0.601 2001 

UMC Hercules Glades 1.882 0.867 2002 

UMC Hercules Glades 0.917 0.593 2003 

UMC Upper Buffalo 1.152 0.518 2001 

UMC Upper Buffalo 1.614 0.819 2002 

UMC Upper Buffalo 0.867 0.470 2003 

Independence P&L Mingo 1.282 1.131 2001 

Independence P&L Mingo 1.071 0.701 2002 

Independence P&L Mingo 1.116 0.629 2003 

Independence P&L Hercules Glade 3.332 1.972 2001 

Independence P&L Hercules Glade 3.016 1.500 2002 

Independence P&L Hercules Glade 0.728 0.358 2003 

Independence P&L Upper Buffalo 2.418 1.136 2001 

Independence P&L Upper Buffalo 1.960 0.909 2002 

Independence P&L Upper Buffalo 0.589 0.683 2003 

Marshall Mingo 0.362 0.430 2001 

Marshall Mingo 1.717 0.994 2002 

Marshall Mingo 0.758 0.378 2003 

Marshall Hercules Glade 1.966 0.453 2001 

Marshall Hercules Glade 1.377 0.523 2002 

Marshall Hercules Glade 0.71 0.420 2003 

Marshall Upper Buffalo 0.825 0.505 2001 

Marshall Upper Buffalo 0.827 0.381 2002 

Marshall Upper Buffalo 0.823 0.519 2003 

Columbia Mingo 0.492 0.250 2001 

Columbia Mingo 1.462 0.808 2002 

Columbia Mingo 0.754 0.244 2003 

Columbia Hercules Glade 0.398 0.236 2001 

Columbia Hercules Glade 0.877 0.391 2002 

Columbia Hercules Glade 0.386 0.238 2003 

Columbia Upper Buffalo 0.517 0.194 2001 

Columbia Upper Buffalo 0.679 0.345 2002 

Columbia Upper Buffalo 0.385 0.184 2003 

Holcim - Clarksville Mingo 5.960 3.078 2001 

Holcim - Clarksville Mingo 3.351 2.084 2002 

Holcim - Clarksville Mingo 2.502 1.357 2003 

Holcim - Clarksville Hercules Glade 3.111 1.420 2001 

Holcim - Clarksville Hercules Glade 3.919 2.530 2002 

Holcim - Clarksville Hercules Glade 1.966 1.084 2003 

Holcim - Clarksville Upper Buffalo 2.705 1.248 2001 

Holcim - Clarksville Upper Buffalo 4.391 2.469 2002 

Holcim - Clarksville Upper Buffalo 1.839 1.072 2003 

BOLD denotes deciview impact over the 0.5 threshold 

Italics denotes sources that were included as a result of a public comment 

* University of Missouri – Columbia 
60

The additional analysis on the two CAIR EGU facilities (Associated Electric – Thomas Hill and 

Aquila – Lake Road) mentioned above did not illustrate any discernable visibility difference (all 

CALPOST values are less than or equal to 0.001). Therefore, results were not presented in Table 

9.3. Emissions from BART-eligible units at BASF Corporation were not included in the 

screening analysis, but were included in the refined screening analysis detailed below. 

In addition to the maximum impact metric shown above in the screening analyses, the State of 

Missouri evaluated the number of days with visibility impacts over the contribute (0.5 deciview) 

and cause (1.0 deciview) thresholds to decide which Class I area would be necessary for refined 

analyses. The results shown in Table 9.4 illustrate the number of days over the threshold for 

each source/Class I area combination. Again, these results were utilized to identify which Class 

I areas were more likely to be impacted and would need further refined analyses. 

Table 9.4: Number of Days over the 0.5 Deciview Threshold 

 Facility Class I Area Method 2 Days Method 6 Days Year 

Noranda Hercules Glades 1 0 2001 

Noranda Hercules Glades 4 1 2002 

Noranda Hercules Glades 1 1 2003 

Noranda Mingo 9 3 2001 

Noranda Mingo 8 4 2002 

Noranda Mingo 10 6 2003 

Noranda Upper Buffalo 0 0 2001 

Noranda Upper Buffalo 5 1 2002 

Noranda Upper Buffalo 3 1 2003 

Noranda Mammoth Cave 1 0 2001 

Noranda Mammoth Cave 4 2 2002 

Noranda Mammoth Cave 1 0 2003 

UMC Hercules Glades 8 2 2001 

UMC Hercules Glades 8 1 2002 

UMC Hercules Glades 7 2 2003 

UMC Mingo 5 2 2001 

UMC Mingo 6 3 2002 

UMC Mingo 8 1 2003 

UMC Upper Buffalo 2 1 2001 

UMC Upper Buffalo 10 3 2002 

UMC Upper Buffalo 6 0 2003 

Independence P&L Mingo 2 1 2001 

Independence P&L Mingo 6 1 2002 

Independence P&L Mingo 4 2 2003 

Independence P&L Hercules Glade 5 5 2001 

Independence P&L Hercules Glade 5 3 2002 

Independence P&L Hercules Glade 2 0 2003 

Independence P&L Upper Buffalo 8 4 2001 

Independence P&L Upper Buffalo 6 1 2002 
61

Independence P&L Upper Buffalo 4 1 2003 

Marshall Mingo 0 0 2001 

Marshall Mingo 3 2 2002 

Marshall Mingo 2 0 2003 

Marshall Hercules Glade 4 1 2001 

Marshall Hercules Glade 7 2 2002 

Marshall Hercules Glade 4 0 2003 

Marshall Upper Buffalo 3 1 2001 

Marshall Upper Buffalo 4 0 2002 

Marshall Upper Buffalo 6 1 2003 

Columbia Mingo 0 0 2001 

Columbia Mingo 2 1 2002 

Columbia Mingo 1 0 2003 

Columbia Hercules Glade 0 0 2001 

Columbia Hercules Glade 2 0 2002 

Columbia Hercules Glade 0 0 2003 

Columbia Upper Buffalo 1 0 2001 

Columbia Upper Buffalo 2 0 2002 

Columbia Upper Buffalo 0 0 2003 

Holcim - Clarksville Mingo 27 29 2001 

Holcim - Clarksville Mingo 28 26 2002 

Holcim - Clarksville Mingo 40 25 2003 

Holcim - Clarksville Hercules Glade 5 7 2001 

Holcim - Clarksville Hercules Glade 18 14 2002 

Holcim - Clarksville Hercules Glade 19 16 2003 

Holcim - Clarksville Upper Buffalo 7 4 2001 

Holcim - Clarksville Upper Buffalo 14 9 2002 

Holcim - Clarksville Upper Buffalo 14 9 2003 

Based on the screening analyses, the State of Missouri required Noranda to submit refined 

modeling for Mingo, and the University of Missouri-Columbia (UMC) to submit refined analysis 

for Mingo, Hercules Glades, and Upper Buffalo. The fundamental difference between both sets 

of refined analyses and the previous screening evaluation was the use of meteorological 

observations in the development of the CALMET files used in the CALPUFF evaluations. The 

emission rates were consistent between the screening analyses and the refined analyses, as were 

the meteorological years for the evaluation (2001-2003). In order to develop the new refined 

meteorological dataset, both companies chose different grid parameters for the evaluation. The 

grid structure is contained in Table 9.5 for both analyses. It should be noted that the UMC 

CALMET analyses were utilized for all the other refined modeling conducted by the department 

based on the revision to the BART-eligible source list detailed above. This means that the same 

meteorological dataset was utilized for refined modeling of: BASF Corporation, Independence 

Power and Light – Blue Valley, Columbia Municipal Power Plant, Marshall Municipal, and 
62

Holcim - Clarksville. Each of these BART-eligible sources were evaluated for Mingo, Hercules 

Glade, and Upper Buffalo Class I areas. 

Table 9.5: Grid Structure for Refined Terrain, Land Use, and CALMET Analyses 

Variable RLAT0 RLON0 RLAT1 RLAT2 XREFKM YREFKM NX NY DGRIDKM 

Noranda 36.0874 90.8491 36 40 0 0 83 80 2.0 

UMC 37 92 30 45 -258 -330 87 111 6.0 

The choices of the domain are appropriate for these evaluations of the relevant Class I areas. 

Please note that based on previous guidance from the FLMs on new source review evaluations, 

the domain for each analysis extends at least 50 km beyond the source(s) and Class I area(s) in 

each direction. The very fine grid spacing for Noranda is due to the proximity of the source to 

the Mingo National Wildlife Refuge (~60 km). The list of terrain and land use files used in the 

analyses for each project is included in Appendix L. 

In addition to the grid structure change, meteorological observations were also utilized to refine 

the MM5 data used in the screening analyses. The lists of specific stations used along with 

relevant locational information for each station and upper air, surface, and precipitation data are 

included in Appendix L. 

Based on the review process and discussions with the facilities during the screening analysis, the 

source parameter, emissions, and many other CALPUFF/CALPOST issues were addressed to 

allow for the use of the screening files as a basis for the development of the refined analysis. 

Nonetheless, the issues noted are presented below for clarification purposes. 

9.3.1 University of Missouri-Columbia 

The review for the BART-eligible unit at UMC (Boiler 10) included the verification of the 

CALPUFF concentration results along with a slightly different methodology for calculation of 

the visibility impacts at the relevant Class I areas. The methodology utilized by the contractor in 

this case included the use of speciation for the PM10 emissions from the boiler and the 

POSTUTIL program for the CALPUFF results. The speciation profile was obtained from the 

National Park Service web site at www2.nature.nps.gov/air/Permits/ect/ectCoalFiredBoiler.cfm

from the Pulverized Coal – Dry Bottom Boiler with fabric filter (baghouse) control spreadsheet. 
63

The department used the PM10 emission rate from the boiler and converted the concentrations 

directly to PMF for calculation of the visibility change at the relevant Class I areas. Each set of 

results is presented below in Table 9.6, 9.7, and 9.8. 

Table 9.6: UMC Refined Analysis Results (Boiler PM Speciation Profile) 

Facility Class I Area Maximum 

Method 6 

Impact 

8th Highest 

(98%) M6 

Impact 

Days over 0.5 

Deciview 

Threshold 

Year 

UMC Mingo 0.291 0.144 0 2001 

UMC Mingo 1.389 0.188 2 2002 

UMC Mingo 0.582 0.323 2 2003 

UMC Hercules Glades 0.709 0.310 2 2001 

UMC Hercules Glades 0.542 0.195 1 2002 

UMC Hercules Glades 0.591 0.271 2 2003 

UMC Upper Buffalo 0.466 0.232 0 2001 

UMC Upper Buffalo 0.714 0.210 1 2002 

UMC Upper Buffalo 0.406 0.226 0 2003 

Table 9.7: UMC Refined Analysis Results (PM10=PMF) Method 2 

Facility Class I Area Maximum 

Method 2 

Impact 

8th Highest 

(98%) M2 

Impact 

Days over 0.5 

Deciview 

Threshold 

Year 

UMC Mingo 0.304 0.193 0 2001 

UMC Mingo 2.757 0.236 2 2002 

UMC Mingo 0.641 0.376 2 2003 

UMC Hercules Glades 0.804 0.377 3 2001 

UMC Hercules Glades 0.524 0.228 1 2002 

UMC Hercules Glades 0.647 0.413 5 2003 

UMC Upper Buffalo 0.855 0.248 2 2001 

UMC Upper Buffalo 0.941 0.227 3 2002 

UMC Upper Buffalo 0.549 0.339 1 2003 

Table 9.8: UMC Refined Analysis Results (PM10=PMF) Method 6 

Facility Class I Area Maximum 

Method 6 

Impact 

8th Highest 

(98%) M6 

Impact 

Days over 0.5 

Deciview 

Threshold 

Year 

UMC Mingo 0.290 0.144 0 2001 

UMC Mingo 1.389 0.188 2 2002 

UMC Mingo 0.581 0.323 2 2003 

UMC Hercules Glades 0.708 0.310 2 2001 

UMC Hercules Glades 0.542 0.195 1 2002 

UMC Hercules Glades 0.591 0.270 2 2003 

UMC Upper Buffalo 0.465 0.232 0 2001 

UMC Upper Buffalo 0.714 0.210 1 2002 

UMC Upper Buffalo 0.405 0.226 0 2003 
64

The results clearly demonstrate that Boiler 10 at the University of Missouri – Columbia does not 

exceed the 98th percentile visibility impact threshold of 0.5 deciview for CALPOST Method 2 

methodology, which is more conservative than the required Method 6 methodology. When 

comparing Table 9.6 and 9.8, it is apparent that the use of the PM10 speciation profile by the 

source did not impact the visibility change. This is due to the fact that SO2 emissions from this 

boiler contribute over 90 percent of the visibility impact at all the relevant Class I areas evaluated 

when the impacts are above 0.5 deciview. Further, the SO2 emissions calculation from this 

source was based on a potential maximum emission rate (maximum hourly design rate * 

emission factor). 

9.3.2 Noranda 

The Noranda evaluation is one of the BART analysis conducted by the State of Missouri with 

emission rates that do not represent the maximum allowable rates for all pollutants. In fact, most 

of the sources from Noranda are represented by the maximum allowable rates. However, there 

are five sources that had maximum 24-hour actual SO2 emissions calculated: (1) EP-59, Monitor 

– Potline 1; (2) EP-60, Monitor – Potline 2; (3) EP-61, Stack – Potline 1&2; (4) EP-98, Carbon 

Bake Furnace 1; and (5) EP-99, Carbon Bake Furnace 2. For the first three sources, the 

methodology for calculating the emissions was as follows: 

1) Obtain the maximum combined daily aluminum tapped for Lines 1 & 2 from 2000-

2005 with the knowledge that tapped aluminum does not necessarily reflect 

production in the plant due to day-to-day carryover of aluminum in certain situations, 

2) Obtain the maximum coke sulfur content, 

3) Calculate the maximum ratio of tons anode consumed to tons aluminum, and 

4) Multiply the maximum daily tapped aluminum (December 24, 2004) by the 

maximum ratio of tons anode/tons aluminum (0.413), the maximum coke sulfur 

content (2.82 percent), and the molecular weight ratio of SO2 to S in the process 

(1.998). 

The resultant calculation follows: 

Line 1 468,725 tons aluminum/day * 0.413 * 0.0282 * 1.998 = 10,907.2 lb SO2/day 
65

Line 2 600,400 tons aluminum/day * 0.413 * 0.0282 * 1.998 = 13,971.3 lb SO2/day 

These emissions were then distributed to the stack and roof monitors using a previous permit 

relationship (95 percent stack vs. 5 percent monitor) for each line. The final modeled emission 

rate for these three sources was: 

Monitor – Potline 1 => 10,907.2 lb SO2/day * 0.05 = 545.4 lb SO2/day 

Monitor – Potline 2 => 13,971.3 lb SO2/day * 0.05 = 698.6 lb SO2/day 

Stack for Potline 1&2 => 24,878.5 lb SO2/day * 0.95 = 23,634.5 lb SO2/day 

It should be noted that the NOX emission rates for these sources also used the same maximum 

tapping rates for this calculation. 

The carbon bake furnace emissions were calculated using the monthly amount of pitch received 

along with the maximum sulfur content of the pitch in any month during the 5-year period. This 

information was evaluated for January 2000 – December 2005. The maximum product of the 

amount and the pitch S content was September 2005 (2,230 tons pitch received). The maximum 

sulfur content in the pitch was observed in November 2005 (0.72 percent S). The calculation of 

emissions from all three furnaces is as follows: 

2,230 tons pitch/month * (0.0072 ton S/ ton pitch) * 1.998 ton SO2/ton S = 

 31.634 ton SO2/month 

Then, the aluminum production at the three potline/furnace combinations for September 2005 

was documented and a production ratio was calculated for each set. This ratio was then 

multiplied for potlines 1 and 2 by the total maximum SO2 emissions/month. The daily 

“maximum” was evaluated using the maximum monthly emissions divided by 30 days/month. 

The calculation of emissions is as follows: 

 14,068,215 September 2005 production Line 1 

 13,844,190 Production Line 2 
66

 15,045,080 Production Line 3 

Percent Line 1 Production = 32.75% 

 Percent Line 2 Production = 32.23% 

 Percent Line 3 Production = 35.02% 

 Line 1 Emissions = 31.634 ton SO2/month * 0.3275 / 30 day/month = 

 0.3453 ton SO2/day = 690.68 lb SO2/day 

 Line 2 Emissions = 31.634 ton SO2/month * 0.3223 / 30 day/month = 

 0.3399 ton SO2/day = 679.71 lb SO2/day 

All these emissions were utilized in both the screening and the refined meteorological 

evaluations for Noranda’s impacts and can be found in Appendix M. 

One issue was identified with respect to the refined analyses completed by Noranda’s contractor. 

In CALMET, the location of the surface, upper air, and precipitation stations is required to allow 

the model to develop the appropriate 3-D meteorological fields for input into CALPUFF. During 

the review, it was discovered that the location of the precipitation stations utilized in the Noranda 

project were based on incorrect latitude and longitude data procured from another source. 

Therefore, at this time, the results presented in Tables 9.9 and 9.10 reflect the previous Noranda 

submittal and the corrected submittal. As can be seen by direct comparison of the results, both 

sets are nearly identical and reflect that Noranda’s BART-eligible sources do not cause or 

contribute to a visibility problem at Mingo. 

Table 9.9: Noranda Refined Analysis Results (Original Submittal) 

Facility Class I 

Area 

Max M2 

Impact 

98% M2 

Impact 

Days > 0.5 

(M2) 

Max M6 

Impact 

98% M6 

Impact 

Days >0.5 

(M6) 

Year 

Noranda Mingo 0.770 0.340 3 0.654 0.373 2 2001 

Noranda Mingo 0.812 0.427 3 0.653 0.416 3 2002 

Noranda Mingo 0.804 0.444 5 0.745 0.406 4 2003 
67

Table 9.10: Noranda Refined Analysis Results (Revised CALMET) 

Facility Class I 

Area 

Max M2 

Impact 

98% M2 

Impact 

Days > 0.5 

(M2) 

Max M6 

Impact 

98% M6 

Impact 

Days >0.5 

(M6) 

Year 

Noranda Mingo 0.769 0.340 2 0.660 0.373 2 2001 

Noranda Mingo 0.775 0.412 3 0.653 0.416 3 2002 

Noranda Mingo 0.799 0.447 5 0.745 0.435 4 2003 

The results clearly demonstrate that the sources at Noranda do not exceed the 98th percentile 

visibility impact threshold of 0.5 deciview even if the more conservative CALPOST Method 2 

methodology is used. 

9.3.3 Independence Power and Light – Blue Valley 

The emission rates used for the BART-eligible unit (Boiler #3) at Independence Power and Light 

were generated by using the maximum boiler heat input (540 MMBTU/hr) and the minimum 

heat content for the coal used over the last five years (10,100 BTU/lb in 2004). This produced a 

maximum hourly design rate of 26.73 tons coal / hour. This design rate was multiplied by the 

highest annual emission factor for the last five years for each pollutant of interest: SO2 – 115.14 

lb SO2/ton coal, 9.70 lb NOX /ton coal, and 35.88 lb PM10/ton coal (pre-control). For PM10, the 

uncontrolled emissions were multiplied by (1-Control Efficiency%/100) to reflect the operation 

of an electrostatic precipitator. The resultant emissions were: 

SO2 -- 26.73 tons coal/hour * 115.14 lb SO2/ ton coal * 24 hours/day = 73,684.6 lb SO2/day

NOX – 26.73 tons coal/hour * 9.7 lb NOX /ton coal * 24 hours/day = 6,222.7 lb NOX /day

PM10 – 26.73 tons coal/hour * 35.88 lb PM10/ton coal * (1-95.5/100) * 24 hours/day = 

1035.80 lb PM10/day

As previously mentioned, the refined meteorological dataset for this analysis was originated by 

the University of Missouri – Columbia. The results of the refined analysis for Mingo, Hercules, 

and Upper Buffalo are presented in Table 9.11 including the 8th highest (98 percentile) values. 

Also, as with the department’s analysis of the University of Missouri – Columbia’s boiler, the 

same PM10 direct conversion to PMF calculation methodology was utilized to determine 

visibility impacts in CALPOST. 
68

Table 9.11: Independence Power and Light Refined Analysis Results 

Facility Class I Area Max M2 

Impact 

98% M2 

Impact 

Days > 

0.5 

(M2) 

Max M6 

Impact 

98% M6 

Impact 

Days 

>0.5 

(M6) 

Year 

Ind. P&L Mingo 0.724 0.288 2 0.513 0.226 1 2001 

Ind. P&L Mingo 1.990 0.346 6 1.415 0.289 3 2002 

Ind. P&L Mingo 0.912 0.295 3 0.487 0.233 0 2003 

Ind. P&L Hercules 1.726 0.328 3 0.890 0.327 2 2001 

Ind. P&L Hercules 1.031 0.283 3 0.506 0.301 1 2002 

Ind. P&L Hercules 0.939 0.345 3 0.501 0.217 1 2003 

Ind. P&L Upper Buffalo 1.097 0.333 5 0.737 0.286 2 2001 

Ind. P&L Upper Buffalo 0.465 0.292 0 0.449 0.277 0 2002 

Ind. P&L Upper Buffalo 0.453 0.263 0 0.455 0.299 0 2003 

The results demonstrate that the source at Independence Power and Light does not exceed the 

98th percentile visibility impact threshold of 0.5 deciview even if the more conservative 

CALPOST Method 2 methodology is used. 

9.3.4 Marshall Municipal Utilities 

The emission rates used for the BART-eligible unit (Coal-fired Boiler – EP05) at Marshall were 

generated by using the maximum boiler heat input (235 MMBTU/hr) and the minimum heat 

content for the coal used over the last five years (10,653 BTU/lb in 2005). This produced a 

maximum hourly design rate of 11.03 tons coal / hour. This design rate was multiplied by the 

highest annual emission factor for the last five years for each pollutant of interest: SO2 – 134.90 

lb SO2/ton coal, 22 lb NOX/ton coal, and 19.92 lb PM10/ton coal (pre-control). For PM10, the 

uncontrolled emissions were multiplied by (1-Control Efficiency%/100) to reflect the operation 

of an electrostatic precipitator. The resultant emissions were: 

SO2 -- 11.03 tons coal/hour * 134.90 lb SO2/ ton coal * 24 hours/day = 35,709.9 lb SO2/day

NOX – 11.03 tons coal/hour * 22 lb NOX/ton coal * 24 hours/day = 5,823.7 lb NOX/day

PM10 – 11.03 tons coal/hour * 19.92 lb PM10/ton coal * (1-87.5/100) * 24 hours/day = 

659.07 lb PM10/day

As previously mentioned, the refined meteorological dataset for this analysis was originated by 

the University of Missouri – Columbia. The results of the refined analysis for Mingo, Hercules, 

and Upper Buffalo are presented in Table 9.12, including the 8th highest (98 percentile) values. 

Also, as with the department’s analysis of the University of Missouri – Columbia’s boiler, the 
69

same PM10 direct conversion to PMF calculation methodology was utilized to determine 

visibility impacts in CALPOST. 

Table 9.12: Marshall Municipal Utilities Refined Analysis Results 

Facility Class I Area Max M2 

Impact 

98% M2 

Impact 

Days > 

0.5 

(M2) 

Max M6 

Impact 

98% M6 

Impact 

Days 

>0.5 

(M6) 

Year 

Marshall Mingo 0.371 0.133 0 0.355 0.104 0 2001 

Marshall Mingo 1.487 0.143 2 0.698 0.143 2 2002 

Marshall Mingo 0.429 0.160 0 0.436 0.143 0 2003 

Marshall Hercules 1.074 0.263 6 0.453 0.235 0 2001 

Marshall Hercules 0.99 0.210 2 0.523 0.173 1 2002 

Marshall Hercules 0.495 0.432 0 0.420 0.211 0 2003 

Marshall Upper Buffalo 0.400 0.184 0 0.416 0.159 0 2001 

Marshall Upper Buffalo 0.474 0.187 0 0.341 0.175 0 2002 

Marshall Upper Buffalo 0.747 0.395 2 0.442 0.236 0 2003 

The results demonstrate that the source at Marshall Municipal Utilities does not exceed the 98th

percentile visibility impact threshold of 0.5 deciview even if the more conservative CALPOST 

Method 2 methodology is used. 

9.3.5 Columbia Municipal Power Plant 

The emission rates used for the BART-eligible unit (Boiler #7– EP02) at Columbia were 

generated by using the maximum boiler heat input (371 MMBTU/hr) and the minimum heat 

content for the coal used over the last five years (13,304 BTU/lb in 2004). This produced a 

maximum hourly design rate of 13.94 tons coal / hour. This design rate was multiplied by the 

highest annual emission factor for the last five years for each pollutant of interest: SO2 – 47.42 

lb SO2/ton coal, 14.74 lb NOX/ton coal, and 13.2 lb PM10/ton coal (pre-control). For PM10, the 

uncontrolled emissions were multiplied by (1-Control Efficiency%/100) to reflect the operation 

of a cyclone/baghouse combination. The resultant emissions were: 

SO2 -- 13.94 tons coal/hour * 47.42 lb SO2/ ton coal * 24 hours/day = 15,868.5 lb SO2/day

NOX – 13.94 tons coal/hour * 14.74 lb NOX/ton coal * 24 hours/day = 4,932.5 lb NOX/day

PM10 – 13.94 tons coal/hour * 13.2 lb PM10/ton coal * (1-99.75/100) * 24 hours/day = 

11.04 lb PM10/day
70

As previously mentioned, the refined meteorological dataset for this analysis was originated by 

the University of Missouri – Columbia. The results of the refined analysis for Mingo, Hercules, 

and Upper Buffalo are presented in Table 9.13 including the 8th-highest (98 percentile) values. 

The same PM10 direct conversion to PMF calculation methodology was utilized to determine 

visibility impacts in CALPOST as with the other boilers reviewed. 

Table 9.13: Columbia Municipal Utilities Refined Analysis Results 

Facility Class I Area Max M2 

Impact 

98% M2 

Impact 

Days > 

0.5 

(M2) 

Max M6 

Impact 

98% M6 

Impact 

Days 

>0.5 

(M6) 

Year 

Columbia Mingo 0.137 0.090 0 0.200 0.074 0 2001 

Columbia Mingo 1.337 0.102 1 0.645 0.095 1 2002 

Columbia Mingo 0.265 0.166 0 0.244 0.152 0 2003 

Columbia Hercules 0.467 0.183 0 0.411 0.130 0 2001 

Columbia Hercules 0.255 0.137 0 0.196 0.102 0 2002 

Columbia Hercules 0.343 0.171 0 0.232 0.119 0 2003 

Columbia Upper Buffalo 0.465 0.098 0 0.241 0.094 0 2001 

Columbia Upper Buffalo 0.401 0.090 0 0.301 0.091 0 2002 

Columbia Upper Buffalo 0.211 0.147 0 0.152 0.100 0 2003 

The results demonstrate that the source at Columbia Municipal Power Plant does not exceed the 

98th percentile visibility impact threshold of 0.5 deciview even if the more conservative 

CALPOST Method 2 methodology is used. 

9.3.6 BASF Corporation - Palmyra 

The emission rates used for the BART-eligible units (124,000 Gallon Nitric Acid Tank – PR08, 

D Incinerator – TC01, A Incinerator – PR53, B Incinerator – PR54, and 2 Natural Gas Fired 

Boilers – UTIL07) at BASF were generated by utilizing the potential throughput for each unit 

and the maximum emission factor over the last five years. The remaining units at this facility 

were installed outside the BART timeframe or did not emit one of the visibility impairing 

pollutants. Unit PR08 has NOX emissions from two components: working loss and breathing 

loss. The working loss throughput was calculated by assessing the maximum amount of acid 

moved through the tank in the last five years (2,130,000 gallons in 2005) and dividing by the 

number of hours acid was “worked” in the tank (5,544 hours – 24 hours, 7 days, 33 weeks). This 

results in 384.1 gallons/hour. The emission factor is 0.16 lb NOX /1000 gallons. The resultant 

emission calculation is: 
71

NOX – 0.3841 1000 gal acid/hour * 0.16 lb NOX/1000 gallon * 24 hours/day = 

1.5 lb NOX/day

The breathing loss was calculated using the tank capacity multiplied by the appropriate emission 

factor. 

NOX – 124 1000 gal capacity * 1.94 lb NOX/1000 gallons / 365 days/year = 

0.66 lb NOX/day

The emissions from the D Incinerator (TC01) utilized the maximum hourly design rate of 

material (7.75 tons/hour) and the maximum emission factor for the last five years for each 

pollutant – all were 2005. The emissions calculations are below: 

SO2 -- 7.75 tons/hour * 3.841 lb SO2/ ton * 24 hours/day = 714.4 lb SO2/day

NOX – 7.75 tons/hour * 1.662 lb NOX/ton * 24 hours/day = 309.1 lb NOX/day

PM10 – 7.75 tons/hour * 1.923 lb PM10/ton * 24 hours/day = 357.7 lb PM10/day

The emissions from the A Incinerator (PR53) utilized the maximum hourly design rate of 

material (25 tons/hour) and the maximum emission factor for the last five years for each 

applicable pollutant – both were 2006. The emissions calculations are below: 

NOX – 25 tons/hour * 8.90 lb NOX/ton * 24 hours/day = 5,340.0 lb NOX/day

PM10 – 25 tons/hour * 1.35 lb PM10/ton * 24 hours/day = 810.0 lb PM10/day

The emissions from the B Incinerator (PR54) utilized the maximum hourly design rate of 

material (25 tons/hour) and the maximum emission factor for the last five years for each 

applicable pollutant – NOX – 2004 and PM10 - 2005. The emissions calculations are below: 

NOX – 25 tons/hour * 3.99 lb NOX/ton * 24 hours/day = 2,394.0 lb NOX/day

PM10 – 25 tons/hour * 0.588 lb PM10/ton * 24 hours/day = 352.5 lb PM10/day
72

The emissions from the two natural gas-fired boilers (UTIL07) utilized the maximum heat input 

of the two boilers (232.5 MMBTU/hour) along with a heat content of 1,050 MMBTU/MMCF for 

natural gas to arrive at 0.2214 MMCF/hour. The emission factor (140 lb NOx / MMCF) was 

obtained from EPA’s AP-42 guidance document. The emissions calculations are below: 

NOX – 0.2214 MMCF/hour * 140 lb NOX/MMCF * 24 hours/day = 743.9 lb NOX/day

As previously mentioned, the refined meteorological dataset for this analysis was originated by 

the University of Missouri – Columbia. The results of the refined analysis for Mingo, Hercules, 

and Upper Buffalo are presented in Table 9.14 including the 8th-highest (98 percentile) values. 

The same PM10 direct conversion to PMF calculation methodology was utilized to determine 

visibility impacts in CALPOST as with the other boilers reviewed. 

Table 9.14: BASF Corporation Refined Analysis Results 

Facility Class I Area Max M2 

Impact 

98% M2 

Impact 

Days > 

0.5 

(M2) 

Max M6 

Impact 

98% M6 

Impact 

Days 

>0.5 

(M6) 

Year 

BASF Mingo 0.152 0.062 0 0.100 0.065 0 2001 

BASF Mingo 0.260 0.059 0 0.153 0.050 0 2002 

BASF Mingo 0.088 0.040 0 0.080 0.038 0 2003 

BASF Hercules 0.210 0.032 0 0.121 0.022 0 2001 

BASF Hercules 0.097 0.020 0 0.081 0.018 0 2002 

BASF Hercules 0.170 0.043 0 0.082 0.030 0 2003 

BASF Upper Buffalo 0.198 0.024 0 0.119 0.012 0 2001 

BASF Upper Buffalo 0.059 0.022 0 0.059 0.018 0 2002 

BASF Upper Buffalo 0.155 0.028 0 0.075 0.020 0 2003 

The results demonstrate that the BART-eligible sources at BASF Corporation - Palmyra Plant do 

not exceed the maximum visibility impact threshold of 0.5 deciview even if the more 

conservative CALPOST Method 2 methodology is used. 

9.3.7 Doe Run - Buick 

The emission rates used in this visibility sensitivity for the BART-eligible unit (Blast Furnace - 

Main Stack EP08) at Doe Run Buick were generated using the 2005 construction permit limits 

for this source. Specifically, the facility-wide SO2 limit was utilized, while the unit specific 

limits for NOx and PM10 were used. The emission rates are as follows: 

SO2 -- 18,630.1 lb SO2/day
73

NOX – 20.6 lb NOX /day

PM10 – 184.8 lb PM10/day

The refined meteorological dataset for this sensitivity was originated by the University of 

Missouri – Columbia. The results of the refined analysis for Mingo are presented in Table 9.15 

including the 8th highest (98 percentile) values. Also, as with the department’s analysis of the 

University of Missouri – Columbia’s boiler, the same PM10 direct conversion to PMF calculation 

methodology was utilized to determine visibility impacts in CALPOST. 

Table 9.15: Doe Run Buick Refined Sensitivity Results 

Facility Class I Area Max M2 

Impact 

98% M2 

Impact 

(8th high) 

Days > 

0.5 

(M2) 

Max M6 

Impact 

98% M6 

Impact 

(8th high) 

Days 

>0.5 

(M6) 

Year 

DR Buick Mingo 1.007 0.230 2 0.643 0.233 2 2001 

DR Buick Mingo 0.714 0.246 2 0.365 0.171 0 2002 

DR Buick Mingo 0.424 0.252 0 0.397 0.203 0 2003 

These results demonstrate that the current set of emissions at Doe Run – Buick will not have an 

adverse impact on the Mingo Refuge and bolster the finding of no additional SO2 control 

necessary for BART. 

9.3.8 Holcim - Clarksville 

Prior to the March 2008 regional haze state implementation plan submittal, there were two 

different modeling analyses conducted for Holcim – Clarksville. The first evaluation utilized 

SO2 and NOX emissions from the calculation documented below (tons clinker per hour X lb 

pollutant / ton clinker). The other analysis utilized a maximum 24-hour actual emission rate for 

SO2 and NOX from 2004-07 based on Holcim’s continuous emission monitoring system. 

The emission rates used in this analysis for the largest BART-eligible units at Holcim – 

Clarksville (EP14 – Main Stack) were generated by using the maximum clinker throughput for 

the kiln (175 tons/hour) and the maximum emission factors over the last five years. The highest 

annual emission factor for the last five years for each pollutant of interest is: SO2 – 22.97 lb 

SO2/ton clinker, 13.89 lb NOX/ton clinker, and 0.22 lb PM10/ton clinker. The resultant emissions 

were: 
74

SO2 -- 175 tons clinker/hour * 22.97 lb SO2/ ton clinker * 24 hours/day = 96,474.0 lb SO2/day

NOX – 175 tons clinker/hour * 13.89 lb NOX /ton clinker * 24 hours/day = 58,338.0 lb NOX /day

PM10 – 175 tons clinker/hour * 0.22 lb PM10/ton coal * 24 hours/day = 924.0 lb PM10/day

The remaining emission points (mostly handling of materials) were only PM10 emissions and 

were calculated based on maximum hourly design rate and emission factor for the particular 

operation. These emission points are further documented in Appendix I. 

As previously mentioned, the refined meteorological dataset for this analysis was originated by 

the University of Missouri – Columbia. The results of the refined analysis for Mingo, Hercules, 

and Upper Buffalo are presented in Table 9.16 including the 8th-highest (98 percentile) values. 

The same PM10 direct conversion to PMF calculation methodology was utilized to determine 

visibility impacts in CALPOST as with the other boilers reviewed. 

Table 9.16: Holcim - Clarksville Refined Analysis Results 

Facility Class I Area Max M2 

Impact 

98% M2 

Impact 

Days > 

0.5 

(M2) 

Max M6 

Impact 

98% M6 

Impact 

Days 

>0.5 

(M6) 

Year 

Holcim Mingo 1.975 1.214 26 1.378 0.924 23 2001 

Holcim Mingo 3.135 1.088 24 1.784 0.834 19 2002 

Holcim Mingo 1.861 1.042 18 1.719 0.734 15 2003 

Holcim Hercules 1.607 0.650 8 1.274 0.480 7 2001 

Holcim Hercules 2.699 0.667 11 1.758 0.799 10 2002 

Holcim Hercules 1.847 0.804 16 1.147 0.626 13 2003 

Holcim Upper Buffalo 1.543 0.389 7 1.101 0.382 5 2001 

Holcim Upper Buffalo 2.847 0.557 10 1.955 0.465 7 2002 

Holcim Upper Buffalo 1.502 0.776 15 1.309 0.580 12 2003 

The refined modeling impacts from Holcim – Clarksville exceed the 0.5 deciview threshold for 

all three Class 1 areas for both the Method 2 and the Method 6 CALPOST methodology. 

Therefore, the department contacted Holcim to pursue control of SO2 and NOX for BART. The 

PM10 impact on visibility is less than 1 percent and does not constitute enough impact to pursue 

control. Holcim initially responded (prior to the March 2008 submittal) that they were in the 

process of retrofitting the kiln under permit #082007-019 that requires them to install a mid-kiln 

firing system for NOX control. As a point of reference, the department determined that mid-kiln 
75

firing was equivalent to a 30 percent reduction from 1990 cement kiln NOX emissions based on 

EPA information provided during the development of the NOX SIP call. 

After the March 2008 SIP submittal, Holcim provided additional information detailing the 

maximum 24-hour SO2 and NOX emissions using continuous emission monitoring (CEM) data. 

Holcim installed the CEM data in 2004, began collection of hourly emission data, and has 

maintained the necessary quality assurance measures to ensure accuracy of this data. The use of 

maximum 24-hour emission rates is the preferred methodology for determination of visibility 

impacts from BART sources (if available). The department utilized the maximum 24-hour 

emission rates provided by Holcim with the necessary filling of missing hourly data. The PM10

emission rates used in the new analysis were identical to the previous screening and refined 

modeling analyses. The resultant emissions obtained from the CEM data were: 

SO2 – 4,900.95 lb SO2/hr = 117,622.7 lb SO2/day on 12/2/2004 

NOX – 3049.39 lb NOX/hr = 73,185.3 lb NOX /day on 11/24/2007 

These emissions were modeled using the refined analysis method described above. The Method 

6 results are presented in Table 9.17. 

Table 9.17: Holcim - Clarksville Post-Submittal Refined Analysis Results 

Facility Class I Area Max M6 

Impact 

98% M6 

Impact 

(8th high) 

Days 

>0.5 

(M6) 

Year 

Holcim Mingo 1.685 1.124 26 2001 

Holcim Mingo 2.183 1.018 25 2002 

Holcim Mingo 2.063 0.894 23 2003 

Holcim Hercules 1.534 0.595 9 2001 

Holcim Hercules 2.129 0.968 11 2002 

Holcim Hercules 1.391 0.769 18 2003 

Holcim Upper Buffalo 1.331 0.465 7 2001 

Holcim Upper Buffalo 2.364 0.572 9 2002 

Holcim Upper Buffalo 1.577 0.716 17 2003 

Based on confirmation of the visibility impacts over the 0.5 deciview impact, Holcim provided a 

BART proposal in late April 2008 that included inherent scrubbing (no additional control) for 

SO2 and existing low NOX burners and cement kiln dust insufflation along with the mid-kiln 

firing of tires at 12 percent fuel rate for NOX control. The mid-kiln firing of tires was estimated 
76

by Holcim to provide a 20 percent reduction from existing NOX emission levels. This submittal 

is included as part of Appendix N. 

Based on the review of the Holcim submittal, the department requested additional SO2 control 

information regarding scrubber problems with opacity and installation cost, cost evaluation of 

“local” fuels (specifically, switching from current petroleum coke at 6 percent sulfur to medium 

sulfur coal), and detailed information regarding sulfur balance of the kiln inputs from fuel and 

other raw materials and outputs as sulfur in product, solid waste streams, and stack exhaust gases 

(SO2). The department was specifically interested in a partial control of the exhaust stream with 

a scrubber that would include a by-pass for part of the stream to help eliminate the opacity 

associated with reduced temperature after SO2 scrubbing. 

Holcim provided revised submittals in June and July 2008 (Appendix O and Appendix P, 

respectively) that addressed the partial stream scrubbing question for the kiln and provided 

sufficient information for the ultimate finding of emissions that would satisfy BART for the kiln 

operation at Clarksville. Holcim proposed a 20 percent reduction of NOX and a 23 percent 

reduction of SO2 from their maximum 24-hour emission rates modeled. The proposal also 

requested this limit be expressed as a 30-day rolling average. Based on a comprehensive review 

of these submittals along with visibility modeling of the impacts from this source, the department 

concluded that the mid-kiln firing of tires (using 12 percent total heat input substitution) and a 

switch from petroleum coke as the primary kiln fuel to 3 percent sulfur coal (along with the tirederived fuel for NOX control) would constitute BART for this source. However, the department 

did not agree with the emission limits proposed by Holcim. Specifically, the department did not 

agree to the use of the percentage reduction from the maximum 24-hour emission rate when 

using a thirty-day rolling average. 

The SO2 finding was based primarily on the economic evaluation of several different control 

scenarios for the kiln including both wet and dry scrubbing of the kiln exhaust gas. The 

department found the overall net cost per ton of cement produced (~$15-20/ton) was excessive 

and would have seriously compromised the Clarksville kiln’s ability to compete in the cement 

production market. The fuel switch provided a significant amount of emission reductions at a 
77

cost of approximately $3/ton cement produced. The overall cost per ton SO2 reduced was 

calculated as $1,148/ton removed. The NOX finding was based on information provided by 

Cinar (kiln design contractor for Holcim) regarding NOX emission rates when burning tirederived fuel and the department’s serious concern over the use of selective non-catalytic 

reduction on the world’s largest long wet cement kiln. The increased certainty of the mid-kiln 

firing of tires, along with the use of low-NOX burners and cement kiln dust insufflation, provide 

a firm basis for the finding of NOX BART at Clarksville. In addition, this reduction of emissions 

was to have very little additional cost for the plant due to the planned installation of the mid-kiln 

firing project. The department findings result in a 20 percent reduction of NOX and a 27 percent 

reduction of SO2 from the maximum 30-day average emissions using the CEM data. As 

provided in the presumptive BART finding for utilities, the emission limits are expressed as 30-

day rolling averages of 42,287 pounds NOX/day and 58,787 pounds SO2/day. The calculation of 

these averages will include all hours when the kiln is not operating and those emissions for both 

pollutants will be entered as zero pounds. Detailed SO2 cost spreadsheets along with 

calculations of emission reductions are included in Appendix Q. 

Refined visibility modeling was conducted with the BART limits prescribed by the department 

using the previous refined modeling analysis as a baseline to determine the extent of visibility 

improvement for each of the three impacted Class I areas. The results are provided in Table 

9.18. 

Table 9.18: Holcim - Clarksville BART Limit Refined Analysis Results 

Facility Class I Area Max M6 

Impact 

 98% M6 

Impact 

(8th high) 

Days 

>0.5 

(M6) 

Year 

Holcim Mingo 0.963 0.598 13 2001 

Holcim Mingo 1.254 0.532 8 2002 

Holcim Mingo 1.094 0.471 7 2003 

Holcim Hercules 0.800 0.331 3 2001 

Holcim Hercules 1.163 0.499 7 2002 

Holcim Hercules 0.734 0.412 4 2003 

Holcim Upper Buffalo 0.697 0.236 4 2001 

Holcim Upper Buffalo 1.293 0.300 3 2002 

Holcim Upper Buffalo 0.825 0.370 3 2003 

These results demonstrate less than the 0.5 deciview threshold for the 98th percentile visibility 

impact at the Hercules Glade and Upper Buffalo Wilderness Areas. Further, great improvement 
78

at the more proximate Mingo National Wildlife Refuge was also demonstrated. The highest 98th

percentile impact was in 2001 and this impact was reduced 47 percent from the original refined 

modeling estimate. 

The BART finding was provided to Holcim on August 18, 2008, along with the rationale for the 

finding and a draft consent agreement drafted by the department to codify the emission 

requirements for Holcim – Clarksville (also included in Appendix R). Subsequent comments 

provided by both Holcim and EPA Region VII necessitated some changes to the draft. In 

December 2008, Holcim informed the department of its intention to stop production at the 

Clarksville facility after the 1st quarter of 2009. A mutual decision was made to finalize the 

agreement in the event that Holcim would need to restart the Clarksville kiln operation in the 

near future. However, at this point, there has been no indication that the kiln will be operated 

further. The final consent agreement was signed by the department on April 14, 2009, and is 

included in Appendix S for inclusion in the regional haze State Implementation Plan. 

As discussed previously, the EPA has found that, as a whole, the CAIR cap-and-trade program 

improves visibility more than implementing BART in states affected by CAIR. The state of 

Missouri has opted to participate in the CAIR program under part 96 AAA-EEE and, therefore, 

the CAIR EGU sources are not required to install, operate, and maintain BART for SO2 or NOX. 

In summary, the State of Missouri has identified one BART-eligible source in Missouri that 

entered into a consent agreement with the department to limit emissions of SO2 and NOX. This 

agreement is the mechanism for enforcement of the BART requirements for this source. All 

other sources were examined and the findings were as follows: 

1) sources were not operating or have a federally-enforceable construction permit to 

shutdown the applicable units, 

2) sources were Clean Air Interstate Rule units (EGUs) that were determined to have 

installed BART based on their CAIR status, 

3) one source was found to have been issued two subsequent Prevention of Significant 

Deterioration permits with a BACT finding, or 
79

4) units were eliminated based on less than the threshold (0.5 deciview) impact from a 

screening analysis (maximum impact) or a refined analysis for four facilities (98 

percent impact) 
80

10.0 REASONABLE PROGRESS GOALS 

10.1 REASONABLE PROGRESS GOAL REQUIREMENTS 

40 CFR 51.308(d)(1) requires Missouri to establish RPGs for each Class I area within the state 

(in dv) that provide for reasonable progress towards achieving natural visibility. In addition, 

EPA released guidance on June 1, 2007 to use in setting RPGs (Appendix N). The goals must 

provide improvement in visibility for the most impaired days, and ensure no degradation in 

visibility for the least impaired days over the plan period. The state must also provide an 

assessment of the number of years it would take to attain natural visibility conditions if 

improvement continues at the rate represented by the RPG. 

The EPA guidance referenced above describes the RPG development process as follows: 

RPGs should be initially developed considering available control measures as 

evaluated using the statutory factors. Based on emission reductions anticipated 

from the resulting control strategy for all visibility impairing pollutants, the state 

should ensure that the RPGs define visibility conditions at, or better than, 

conditions based on the uniform rate of progress. If a state finds that its initial 

RPG will not result in visibility improvement equal to or better than the uniform 

rate of progress, then the state should reconsider available control measures, and 

additional measures should be evaluated as appropriate. The RPGs should then 

be revised based upon a more stringent suite of controls. 

The “statutory factors” that the state must consider are identified in 40 CFR 51.308(d)(1)(i)(A) 

as: 

a) The costs of compliance, 

b) The time necessary for compliance, 

c) The energy and non-air quality environmental impacts of compliance, and 

d) The remaining useful life of existing sources that contribute to visibility 

impairment. 

The state must demonstrate how these factors were taken into consideration in selecting the goal 
81

for its mandatory Class I areas. 

10.2 MISSOURI REASONABLE PROGRESS GOAL 

In determining reasonable progress goals, CAA §169A(g)(1) requires states to take into 

consideration four factors, however, flexibility in consideration of factors may be used. The 

EPA guidance indicates that 

...the factors could be used to select which sources or activities should or should 

not be regulated, or they could be used to determine the level or stringency of 

control, if any, for selected sources or activities, or some combination of both. 

The factors may be considered both individually and/or in combination. As noted 

in section 4.1, given the significant emissions reductions that we anticipate to 

result from BART, the CAIR, and the implementation of other CAA programs, 

these reductions may be all that is necessary to achieve reasonable progress in 

the first planning period for some States. Also, as noted in section 4.2, it is not 

necessary for you to reassess the reasonable progress factors for sources subject 

to BART for which you have already completed a BART analysis. 

Missouri’s four-factor analysis for this Regional Haze Plan is achieved using the factor analyses 

conducted by EPA, CENRAP and other RPOs. Chapter 11, the Long-Term Strategy Plan, 

identifies the control measures necessary to achieve the Reasonable Progress Goals. The BART 

analysis for Missouri also contributes to the four-factor analysis. 

10.2.1 Cost and time necessary for compliance factor analysis by EPA 

The analyses in this Regional Haze Plan demonstrate that the 2018 visibility goals for Mingo and 

Hercules Glades have been largely achieved through EGU emission reductions. These 

reductions will be energy and environmental neutral, but are clearly most effective in improving 

haze levels. In addition, controls under CAIR are effective for a considerable lifetime of the 

operating units. A discussion in the CAIR rule highlighted below (70 FR 25197) addresses their 

analysis of reasonable progress factors of cost and time necessary for compliance. 

From past experience in examining multi-pollutant emissions trading programs 

for SO2 and NOX, EPA recognized that the air pollution control retrofits that 
82

result from a program to achieve highly cost-effective reductions are quite 

significant and can not be immediately installed. Such retrofits require a large 

pool of specialized labor resources, in particular, boilermakers, the availability of 

which will be a major limiting factor in the amount and timing of reductions. 

Also, EPA recognized that the regulated industry will need to secure large 

amounts of capital to meet the control requirements while managing an already 

large debt load, and is facing other large capital requirements to improve the 

transmission system. Furthermore, allowing pollution control retrofits to be 

installed over time enables the industry to take advantage of planned outages at 

power plants (unplanned outages can lead to lost revenue) and to enable project 

management to learn from early installations how to deal with some of the 

engineering challenges that will exist, especially for the smaller units that often 

present space limitations. 

Based on these and other considerations, EPA determined in the NPR that the 

earliest reasonable deadline for compliance with the final highly cost-effective 

control levels for reducing emissions was 2015 (taking into consideration the 

existing bank of title IV SO2 allowances). First, the Agency confirmed that the 

levels of SO2 and NOX emissions it believed were reasonable to set as annual 

emissions caps for 2015 lead to highly cost-effective controls for the CAIR region. 

Once EPA determined the 2015 emissions reductions levels, the Agency 

determined a proposed first (interim) phase control level that would commence 

January 1, 2010, the earliest the Agency believed initial pollution controls could 

be fully operational (in today's final action, the first NOX control phase 

commences in 2009 instead of in 2010, as explained in detail in section IV.C). The 

first phase would be the initial step on the slope of emissions reductions (the 

glide-path) leading to the final (second) control phase to commence in 2015. The 

EPA determined the first phase based on the feasibility of installing the necessary 

emission control retrofits, as described in section IV.C. 
83

Although EPA's primary cost-effectiveness determination is for the 2015 

emissions reductions levels, the Agency also evaluated the cost effectiveness of the 

first phase control levels to ensure that they were also highly cost effective. 

Throughout this preamble section, EPA reports both the 2015 and 2010 (and 

2009 for NOX) cost-effectiveness results, although the first phase levels were 

determined based on feasibility rather than cost effectiveness. The 2015 emissions 

reductions include the 2010 (and 2009 for NOX) emissions reductions as a subset 

of the more stringent requirements that EPA is imposing in the second phase.

10.2.2 Cost analysis by CENRAP 

CENRAP, assisted by Alpine Geophysics, conducted additional cost analysis for its 10 Class I 

areas including Mingo and Hercules Glades areas in Missouri. Alpine primarily looked at 

controls on EGUs; Industrial, Commercial and Institutional (ICI) boilers; internal combustion 

engines; and cement kilns. Most of the Missouri facilities identified in the analysis were EGUs 

already participating in federal CAIR rule. The analysis also provided recommendations on 

additional controls for non-EGUs, which were considered but not adopted due to the following 

reasons: 

 Proposed controls are not cost effective – over $2,000 per ton of SO2 or NOX

 Emissions below the threshold limit of 100 tons 

 Sources passed the BART screening analysis 

 Sources already installed controls required by the NOX SIP Call 

10.2.3 Four-factor analysis by MRPO 

In addition to the EPA and Alpine’s analyses, the MRPO and the Minnesota Pollution Control 

Agency published a report on the four-factor analysis (referred to as the “4-factor report”). The 

report looked at the factors in a nine-state area (Minnesota, Wisconsin, Michigan, Indiana, 

Illinois, Missouri, Iowa, North Dakota, and South Dakota.). The 4-factor report primarily looked 

at controls on EGUs; ICI boilers; reciprocating engines and turbines; and mobile sources. Tables 

summarizing the nine-state impacts are listed in the appendices of this published report. 
84

10.2.3.1 Cost of compliance and remaining useful life 

The 4-factor report looked at the cost effectiveness of additional SO2 and NOX emissions 

reduction using two possible control strategies categorized as EGU1 and EGU2. The EGU1 

scenario would cap EGU NOX emissions at 0.10 lb/MMBtu of fossil fuel consumption and SO2

would be limited to 0.15 lb/MMBtu of fossil fuel consumption at EGUs. The EGU2 caps are 

more stringent at 0.07 lb/MMBtu and 0.10 lb/MMBtu of fossil fuel consumption for NOX and 

SO2, respectively. The caps are not enforced at the unit level but represent a proposed region 

wide average emission rate to be met through a trading program. 

Missouri has concluded that additional controls from ICI boilers is unwarranted. Costs across 

the nine-state region, in terms of dollars per deciview, exceed two billion dollars. Similar 

reasons apply to other point sources, such as reciprocating engines and combustion turbines. 

Because Missouri has determined that additional emission controls are not required based on the 

cost of compliance, it is not necessary to determine the remaining useful life of each unit. 

10.2.3.2 Energy and non-air quality environmental impacts of compliance 

The 4-factor report also demonstrates the energy and non-air quality environmental impacts of 

controlling emissions. In the nine-state region, carbon dioxide emissions are projected to 

increase from 3,766,000 tons/year to 5,302,000 tons/year due to the EGU1 and EGU2 controls, 

respectively. 

An additional 1,128,000 – 1,919,000 gallons of wastewater per year is projected to be produced 

by 2018 in the nine-state region under the EGU1 and EGU2 controls, respectively. The 4-factor 

report states that the additional gallons would be treated in existing facilities. The cost of 

treating the additional wastewater and the likelihood of new facilities increases the costs of 

compliance. 

The nine-state region would also incur a projected increase in solid waste production by 2018 of 

347,000 – 538,000 tons as part of the EGU1 and EGU2 controls, respectively. The process of 

siting a new landfill can take decades. 
85

10.2.4 Missouri reasonable progress goals 

It is reasonable to implement CAIR as EPA intended during the first regional haze planning 

period. Missouri’s four-factor analysis finds that ongoing air pollution control programs, 

including CAIR, BACT, and BART, are sufficient to meet the 2018 Uniform Rate of Progress 

for the Mingo and Hercules Glades Class 1 areas. Missouri has adopted EPA’s CAIR cap and 

trade program and will participate fully in the SO2, annual NOX, and ozone season NOx trading 

programs. Missouri’s intent is to allow the market forces of the CAIR cap and trade program to 

drive the installation and operation of cost efficient controls. 

 Figures 8.1a and 8.1.b. show the Uniform Rate of Progress (URP) and modeled 2018 visibility 

projections. The 2018 projections were below the URPs for both Missouri Class I areas. 

Missouri has determined that the modeled rate of visibility improvement by 2018 shown in Table 

10.1 is reasonable and hereby adopts it as the RPG for the listed Class I areas. Table 10.1 

provides a Uniform Rate of Progress and Reasonable Progress for Class I areas in Missouri. 

Table 10.1: Uniform Rate of Progress and Reasonable Progress Goals for 

Class I areas in Missouri 

Class I Area 

2000/2004 

Baseline 

Conditions (dv) 

2018 URP 

Point (dv) 

2018 Modeled 

Predictions 

(dv) 

2064 Natural 

Background 

Conditions 

(dv) 

Deciview 

Improvement 

Needed by 2018 

assuming RPG 

Progress 

Annually to 

2018 assuming 

RPG (dv) 

Mingo 28.02 24.37 23.71 12.40 4.31 0.308 

Hercules Glades 26.75 23.14 23.06 11.30 3.69 0. 264 

To ensure that the emissions from new stationary sources and major modifications will be 

consistent with making reasonable progress toward the national visibility goal, Missouri has a 

requirement to do a visibility impairment evaluation as part of the major construction permitting 

process. 

10.3 CONSULTATION

In determining a reasonable progress rate for each Class I area discussed above, Missouri has 

consulted with FLMs and the other states/tribes, which (are) reasonably anticipated to cause or 
86

contribute to visibility impairment in each of these Class I areas. A description of the 

consultation process is provided in Appendix E, United States Central Class I Areas 

Consultation Plan, Missouri Department of Natural Resources, 2007. In addition, the minutes 

from those meetings are in Appendix U) 

10.4 REPORTING

Progress will be reported to the EPA every five years in accordance with 51.308 (g). 
87

11.0 LONG-TERM STRATEGY TO REACH REASONABLE 

PROGRESS GOALS 

11.1 LONG-TERM STRATEGY REQUIREMENTS

40 CFR 51.308(d)(3) requires Missouri to submit a long-term strategy that addresses regional 

haze visibility impairment for each mandatory Class I federal area within and outside the state, 

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

enforceable emissions limitations, compliance schedules and other measures necessary to 

achieve the RPGs established by states/tribes where the Class I areas are located. This chapter 

describes how Missouri meets the long-term strategy requirements. 

11.2 CONSULTATION

Missouri will continue to coordinate and consult with the consultation stakeholders during the 

development of future progress reports and plan revisions, as well as during the implementation 

of programs having the potential to contribute to visibility impairment in the mandatory Class I 

areas. Face to face meetings will be held if deemed necessary. Otherwise, consultation will be 

in the form of conference calls and/or letter or email correspondence. The Central Class I areas 

consultation will be initiated through the Central Class I areas contacts listed in the consultation 

plan (Appendix E). 

Missouri also participated in the consultation processes for Arkansas, Oklahoma and Minnesota; 

and will continue to participate in other consultation processes in response to any other states 

that request our participation. 

11.3 SHARE OF EMISSION REDUCTIONS

40 CFR 51.308(d)(3)(ii) requires Missouri to demonstrate that its implementation plan includes 

all measures necessary to obtain its fair share of emission reductions needed to meet RPGs. 

Missouri relied on technical analyses developed by CENRAP and additional weight of evidence 

analysis developed as part of consultation planning to determine contributing states (Appendix 

E). Nine states, including Missouri, Arkansas, Kentucky, Illinois, Indiana, Ohio, Oklahoma, 
88

Tennessee and Texas, were identified as contributing to visibility in Mingo and/or Hercules 

Glades Class I areas. The modeling demonstration has shown that the emission reductions from 

these contributing states are sufficient to achieve RPGs in Missouri’s Class I areas. 

Current visibility is estimated from monitored components of PM2.5 and coarse mass. Models 

are used in a relative sense to estimate how current concentrations respond to emission reduction 

measures. Data analysis is used to identify source categories and regions. Current 

concentrations of particulate matter components are adjusted by the relative modeled response to 

estimate concentrations at the end the first implementation period in 2018. Future visibility is 

estimated from estimated component concentrations of PM2.5 and PM10 at the end of the first 

implementation period. The difference between present visibility and future estimated visibility 

is compared with the RPGs to determine if the goal is met. The CENRAP technical analyses on 

visibility conditions and RPGs projections can be found in Appendix F. All applicable measures 

reflected in the modeling demonstration and weight of evidence analysis have been incorporated 

in the state’s long-term strategy. Section 11.4 provides information on these control measures. 

11.4 LONG-TERM STRATEGY COMPONENTS 

40 CFR 51.308(d)(3)(v) requires Missouri to consider several factors in developing its long-term 

strategy. The ongoing air pollution control programs described in section 11.4.1. below were 

used in the modeling demonstration to show that Missouri Class I Areas meet the 2018 RPG. 

Additional controls beyond the RPG modeling demonstration that may be considered for use in 

the long term strategy at a future date are described in section 11.4.2 below. 

11.4.1 Ongoing air pollution control programs – “on the books” controls 

40 CFR 51.308(d)(3)(v)(A) requires states to consider emission reductions from ongoing 

pollution control programs. The NOX and SO2 emissions reductions resulting from these 

ongoing programs will help improve air quality throughout the state of Missouri. 

Missouri used the following “on the books” control programs in the modeling demonstration to 

meet the RPG requirements as presented in Table 10.1 of this Regional Haze Plan. The 

substantial improvements in visibility impairment at the Mingo site for the worst 20 percent days 
89

from 2002 (141 Mm-1) to 2018 (96 Mm-1) is primarily due to reductions in SO4 (35 Mm-1 

improvement) from elevated point sources (Figures E-7a through E-7d of the TSD). Elevated 

point sources also contribute over half to the total extinction for the worst 20 percent days at 

Hercules Glades in 2002 (Figures E-6a and E-6b of the TSD). Going from 2002 to 2018 the 

contributions due to elevated point sources (essentially CAIR and NOX SIP call), on-road mobile 

and non-road mobile are reduced substantially, over 25 Mm-1. 

11.4.1.1 Clean Air Interstate Rule (CAIR) 

On March 10, 2005, EPA signed the CAIR, following three years modeling study and cost 

analysis on SO2 and NOX controls. 

As required by CAIR, Missouri developed draft rules through the workgroup process. 

The rules were presented for public hearing at the December 7, 2006, MACC Meeting and they 

were adopted at the February 1, 2007, MACC Meeting. The rules establish a cap and trade 

system for NOX and SO2 emissions, and Missouri sources will be included in the national 

program. The state rules are 10 CSR 10-6.362 Clean Air Interstate Rule Annual NOX Trading 

Program and 10 CSR 10-6.366 Clean Air Interstate Rule SOX Trading Program. The state rules 

include schedules for compliance, sources affected by the rule and emissions limitations. 

Table 11.1 summarizes the NOX emissions cap for each unit for each calendar year between 

2009-2014 and 2015 and beyond. Table 11.2 summarizes the SO2 emissions cap for each unit 

for each calendar year between 2010-2014 and 2015 and beyond. These rules can be found in 

Appendix V. 
90

Table 11.1: CAIR NOX Emissions Allocation (tons/yr) 

County Plant Facility Name Unit ID 2009 - 2014 2015 and 

beyond 

097 0001 EMPIRE - ASBURY 1 1,097 914 

095 0022 KCPL - HAWTHORN 5A 3,294 2,743 

095 0022 KCPL - HAWTHORN 6 31 26 

095 0022 KCPL - HAWTHORN 7 18 15 

095 0022 KCPL - HAWTHORN 8 16 13 

095 0022 KCPL - HAWTHORN 9 69 58 

083 0001 KCPL - MONTROSE 1 911 759 

083 0001 KCPL - MONTROSE 2 947 788 

083 0001 KCPL - MONTROSE 3 942 784 

095 0023 KCPL - NORTHEAST 11 3 2 

095 0023 KCPL - NORTHEAST 12 2 2 

095 0023 KCPL - NORTHEAST 13 7 6 

095 0023 KCPL - NORTHEAST 14 5 5 

095 0023 KCPL - NORTHEAST 15 4 4 

095 0023 KCPL - NORTHEAST 16 3 2 

095 0023 KCPL - NORTHEAST 17 6 5 

095 0023 KCPL - NORTHEAST 18 4 3 

051 0049 AMEREN - FAIRGROUNDS 2 2 

037 0003 AQUILA - RALPH GREEN 3 9 8 

095 0031 AQUILA - SIBLEY 1 306 255 

095 0031 AQUILA - SIBLEY 2 305 254 

095 0031 AQUILA - SIBLEY 3 1,977 1,646 

031 0090 AMEREN VIADUCT - -

021 0004 AQUILA - LAKE ROAD 6 542 452 

021 0004 AQUILA - LAKE ROAD 5 5 4 

189 0023 AMEREN - HOWARD BEND 1 1 

071 0003 AMEREN - LABADIE 1 2,913 2,425 

071 0003 AMEREN - LABADIE 2 2,998 2,496 

071 0003 AMEREN - LABADIE 3 3,329 2,772 

071 0003 AMEREN - LABADIE 4 2,984 2,484 

189 0010 AMEREN - MERAMEC 1 730 607 

189 0010 AMEREN - MERAMEC 2 676 562 

189 0010 AMEREN - MERAMEC 3 1,171 975 

189 0010 AMEREN - MERAMEC 4 1,778 1,480 

189 0010 AMEREN - MERAMEC GT1 2 2 

189 0010 AMEREN - MERAMEC GT2 3 2 

183 0001 AMEREN - SIOUX 1 2,318 1,930 

183 0001 AMEREN - SIOUX 2 2,282 1,900 

117 0002 CHILLICOTHE 2 2 

019 0002 COLUMBIA 6 41 34 

019 0002 COLUMBIA 7 44 36 

019 0002 COLUMBIA 8 1 -

095 0050 BLUE VALLEY POWER 3 161 134 

095 0050 BLUE VALLEY POWER GT1 - -

077 0005 CU - JAMES RIVER GT1 15 12 

077 0005 CU - JAMES RIVER GT2 9 8 

077 0005 CU - JAMES RIVER 3 293 244 
91

077 0005 CU - JAMES RIVER 4 360 300 

077 0005 CU - JAMES RIVER 5 614 511 

143 0004 AECI - NEW MADRID 1 2,747 2,287 

143 0004 AECI - NEW MADRID 2 3,035 2,527 

175 0001 AECI - THOMAS HILL MB1 1,126 938 

175 0001 AECI - THOMAS HILL MB2 1,663 1,385 

175 0001 AECI - THOMAS HILL MB3 4,046 3,369 

151 0002 CENTRAL ELECTRIC - CHAMOIS 2 315 263 

165 0007 KCPL - IATAN 1 3,990 3,322 

095 0139 AQUILA - GREENWOOD ENERGY CENTER 1 12 10 

095 0139 AQUILA - GREENWOOD ENERGY CENTER 2 12 10 

095 0139 AQUILA - GREENWOOD ENERGY CENTER 3 14 12 

095 0139 AQUILA - GREENWOOD ENERGY CENTER 4 15 12 

099 0016 AMEREN - RUSH ISLAND 1 2,882 2,399 

099 0016 AMEREN - RUSH ISLAND 2 2,748 2,287 

077 0039 SOUTHWEST 1 1,339 1,115 

077 0039 SOUTHWEST CT1A 3 2 

077 0039 SOUTHWEST CT1B 3 2 

077 0039 SOUTHWEST CT2A 3 2 

077 0039 SOUTHWEST CT2B 3 2 

097 0062 EMPIRE – ENERGY CENTER 3A 2 2 

097 0062 EMPIRE – ENERGY CENTER 3B 2 2 

097 0062 EMPIRE – ENERGY CENTER 4A 2 2 

097 0062 EMPIRE – ENERGY CENTER 4B 2 2 

097 0062 EMPIRE – ENERGY CENTER 1 1 21 18 

097 0062 EMPIRE – ENERGY CENTER 2 2 19 16 

007 0012 AMEREN – MEXICO 2 2 

175 0010 AMEREN - MOBERLY 2 1 

051 0008 AMEREN - MOREAU 2 2 

201 0017 SIKESTON 1 1,556 1,295 

097 0104 EMPIRE - STATE LINE 1 78 65 

097 0104 EMPIRE - STATE LINE 2-1 122 101 

097 0104 EMPIRE - STATE LINE 2-2 153 127 

069 0066 ST. FRANCIS POWER PL 1 92 77 

069 0066 ST. FRANCIS POWER PL 2 70 58 

207 0064 ESSEX POWER PLANT 1 11 9 

147 0032 NODAWAY POWER PLANT 1 11 9 

147 0032 NODAWAY POWER PLANT 2 11 9 

101 0051 HOLDEN POWER PLANT 1 2 2 

101 0051 HOLDEN POWER PLANT 2 4 3 

101 0051 HOLDEN POWER PLANT 3 2 2 

077 0164 CU - MCCARTNEY MGS1A 1 1 

077 0164 CU - MCCARTNEY MGS1B 1 1 

077 0164 CU - MCCARTNEY MGS2A 1 1 

077 0164 CU - MCCARTNEY MGS2B 1 1 

163 0047 AMEREN - PENO CREEK CT1A 2 1 

163 0047 AMEREN - PENO CREEK CT1B 2 1 

163 0047 AMEREN - PENO CREEK CT2A 2 1 

163 0047 AMEREN - PENO CREEK CT2B 2 1 

163 0047 AMEREN - PENO CREEK CT3A 2 1 
92

163 0047 AMEREN - PENO CREEK CT3B 2 1 

163 0047 AMEREN - PENO CREEK CT4A 1 1 

163 0047 AMEREN - PENO CREEK CT4B 1 1 

107 0038 HIGGINSVILLE 3 3 

037 0056 MEP PLEASANT HILL CT-1 99 82 

037 0056 MEP PLEASANT HILL CT-2 91 76 

007 0053 AMEREN - AUDRAIN CT1 1 1 

007 0053 AMEREN - AUDRAIN CT2 1 -

007 0053 AMEREN - AUDRAIN CT3 1 -

007 0053 AMEREN - AUDRAIN CT4 1 -

007 0053 AMEREN - AUDRAIN CT5 1 1 

007 0053 AMEREN - AUDRAIN CT6 - -

007 0053 AMEREN - AUDRAIN CT7 - -

007 0053 AMEREN - AUDRAIN CT8 - -

019 0105 COLUMBIA ENERGY CTR CT01 1 1 

019 0105 COLUMBIA ENERGY CTR CT02 1 1 

019 0105 COLUMBIA ENERGY CTR CT03 1 -

019 0105 COLUMBIA ENERGY CTR CT04 - -

 EE/RE set aside 300 300 

 TOTAL 59,871 49,892 

Table 11.2: CAIR SO2 Emissions Allocation (tons/yr) 

County Plant Facility Name Unit ID 2010 Acid Rain 

Allowances 

2010- 2014 

(tons/yr) 2015/after 

097 0001 EMPIRE - ASBURY 1 6,986 3,493 2,445 

095 0050 BLUE VALLEY 3 4,678 2,339 1,637 

151 0002 CENTRAL ELECTRIC - CHAMOIS 2 5,466 2,733 1,913 

019 0002 COLUMBIA 7 3,639 1,820 1,274 

019 0002 COLUMBIA 6 905 453 317 

019 0002 COLUMBIA 8 125 63 44 

095 0022 KCPL - HAWTHORN 5 12,309 6,155 4,308 

165 0007 KCPL - IATAN 1 16,236 8,118 5,683 

077 0005 CU - JAMES RIVER 5 2,136 1,068 748 

077 0005 CU - JAMES RIVER 4 1,253 627 439 

077 0005 CU - JAMES RIVER 3 681 341 238 

077 0005 CU - JAMES RIVER **GT2 605 303 212 

071 0003 AMEREN - LABADIE 1 17,583 8,792 6,154 

071 0003 AMEREN - LABADIE 3 17,516 8,758 6,131 

071 0003 AMEREN - LABADIE 2 16,391 8,196 5,737 

071 0003 AMEREN - LABADIE 4 15,611 7,806 5,464 

021 0004 AQUILA - LAKE ROAD 6 606 303 212 

189 0010 AMEREN - MERAMEC 4 2,554 1,277 894 

189 0010 AMEREN - MERAMEC 3 2,362 1,181 827 

189 0010 AMEREN - MERAMEC 2 1,105 553 387 

189 0010 AMEREN - MERAMEC 1 1,029 515 360 

083 0001 KCPL - MONTROSE 3 4,356 2,178 1,525 

083 0001 KCPL – MONTROSE 2 3,541 1,771 1,239 

083 0001 KCPL – MONTROSE 1 3,194 1,597 1,118 
93

143 0004 AECI – NEW MADRID 2 14,033 7,017 4,912 

143 0004 AECI – NEW MADRID 1 12,198 6,099 4,269 

099 0016 AMEREN - RUSH ISLAND 2 15,518 7,759 5,431 

099 0016 AMEREN - RUSH ISLAND 1 13,900 6,950 4,865 

095 0031 AQUILA – SIBLEY 3 7,648 3,824 2,677 

095 0031 AQUILA – SIBLEY 2 639 320 224 

095 0031 AQUILA – SIBLEY 1 520 260 182 

201 0017 SIKESTON 1 6,802 3,401 2,381 

183 0001 AMEREN – SIOUX 1 10,842 5,421 3,795 

183 0001 AMEREN – SIOUX 2 9,507 4,754 3,327 

077 0039 CU – SOUTHWEST 1 4,127 2,064 1,444 

175 0001 AECI - THOMAS HILL MB3 18,288 9,144 6,401 

175 0001 AECI - THOMAS HILL MB2 7,444 3,722 2,605 

175 0001 AECI - THOMAS HILL MB1 4,429 2,215 1,550 

 TOTAL 266,762 133,381 93,367 

 

* 0.5 multiplier for CAIR allowances between 2010-2014 

** 0.35 multiplier for CAIR allowances 2015 and after 

The long-term strategy also includes any CAIR controls that are being undertaken in other 

impacting states that were identified during the Central Class I areas consultation process. 

11.4.1.2 BART 

Twenty-six potential BART sources have been identified. Twenty-five have been dropped 

through the screening and refined analyses. The remaining source (Holcim – Clarksville) 

entered into a consent agreement with the Missouri Department of Natural Resources to limit 

emissions of SO2 and NOX. No other sources were found to be subject to BART and, therefore, 

implementation of an emissions trading program, other emission controls or other alternative 

measure in place of BART are not necessary. Detailed analyses can be found in Chapter 9 of the 

SIP. 

Missouri will include BART controls proposed by the eight other impacting states in its longterm strategy. Arkansas, Oklahoma and Texas have already had their BART rules proposed. 

Missouri is working with these states to document the emissions reduction and control measures 

required from their sources. Since not all of the BART determinations are completed for other 

states, the five-year review will be the mechanism used to adjust the Reasonable Progress Goal 

based on the other states’ final BART determinations. 
94

11.4.1.3 Other federal ongoing air pollution control programs 

Tier 2 

Tier 2 standards are federal emission standards for passenger cars, light trucks and larger 

passenger vehicles. The program is designed to focus on reducing the emissions most 

responsible for the ozone and PM impact from these vehicles – NOX and non-methane organic 

gases, consisting primarily of hydrocarbons and contributing to VOCs. The Tier 2 standards will 

reduce new vehicle NOX levels to an average of 0.07 grams per mile. For new passenger cars 

and light duty trucks, these standards were phased in starting in 2004, and the standards were 

fully phased in by 2007. For heavy trucks and similar vehicles, the Tier 2 standards will be 

phased in beginning in 2008, with full compliance in 2009. 

During the phase-in period from 2004-2007, all passenger cars and light trucks not certified to 

the primary Tier 2 standards had to meet an interim average standard of 0.30 g/mi NOX. During 

the period 2004-2008, heavy trucks and similar vehicles not certified to the final Tier 2 standards 

will phase in to an interim program with an average standard of 0.20 g/mi NOX, with those not 

covered by the phase-in meeting a per-vehicle standard (i.e., an emissions “cap”) of 0.60 g/mi 

NOX trucks and 0.09 g/mi for similar vehicles. 

Tier 4 

EPA's Clean Air Nonroad Diesel Rule (Tier 4) requires stringent pollution controls on diesel 

engines used in industries such as construction, agriculture and mining, and it will slash sulfur 

content of diesel fuel. This rule is the latest in a series of actions that are designed to reduce 

emissions from nearly every type of diesel vehicle and equipment. This nonroad diesel program 

combines cleaner engine technologies with cleaner fuel – similar to the on-highway diesel 

program. The standards will cut emissions from nonroad diesel engines by over 90 percent. 

Nonroad diesel equipment, as described in this rule, currently accounts for 47 percent of diesel 

PM and 25 percent of NOX from mobile sources nationwide. 

Sulfur levels will also be reduced in nonroad diesel fuel by 99 percent from current levels (from 

approximately 3,000 parts per million (ppm) now to 15 ppm in 2010). The lower sulfur fuel will 

also reduce PM from engines in existing nonroad equipment. It makes it possible for engine 
95

manufacturers to use advanced clean technologies, similar to catalytic technologies used in 

passenger cars. The new engine standards take effect, based on engine horsepower, starting in 

2008. 

11.4.1.4 NOX SIP Call 

The NOX SIP call was designed to assist downwind ozone areas in attaining the one-hour and 8-

hour ozone NAAQS by providing upwind NOX emission control. This rulemaking was 

developed through the EPA’s interpretation of the Ozone Transport Assessment Group 

recommendations and subsequent modeling and cost analysis of NOX controls to reduce ozone 

transport. The final NOX SIP call was published in the Federal Register on October 27, 1998. 

Missouri’s initial rule in response to the NOX SIP Call, 10 CSR 10-6.350 Emission Limitations 

and Emissions Trading of Oxides of Nitrogen, was adopted by the MACC on April 24, 2003. 

The rule established an emission limitation of 0.25 lbs NOX /MMBtu heat input for electric 

generating units in the eastern one-third of the state and a lower limit of 0.18 lb/MMBtu heat 

input for Labadie, Rush Island, and Meramec power plants. EGUs in the western two-third of 

the state were limited to an emission rate of 0.35 lbs NOX /MMBtu of heat input. Cyclone 

boilers (Sibley and Asbury power plants) that burn tire-derived fuels are allowed to meet 0.68 lbs 

NOX /MMBtu heat input. The compliance date was May 1, 2004. 

On April 21, 2004, the EPA finalized the second phase of NOX SIP call. Phase II of the SIP call 

excluded the portion known as the “coarse grid” (the western 2/3 of Missouri) from the NOX SIP 

Call, defined the area of the eastern 1/3 of Missouri to include the same counties as established in 

10 CSR 10-6.350, with the one exception of not including Phelps County, and revised the cap for 

NOX emissions from the previous statewide budget of 114,532 tons of NOX per ozone season to 

a partial state budget of 61,406 tons of NOX per ozone season in the eastern 1/3 of Missouri. The 

budget assumed control levels of 0.15 lbs/MMBtu for electric generating units, 82 percent 

emissions reductions for large natural gas-fired stationary internal combustion engines, 90 

percent emissions reductions for diesel and dual fuel stationary internal combustion engines, 60 

percent emissions reductions for non-utility boilers and turbines, and 30 percent emissions 

reductions for cement manufacturing plants. Small cogeneration units were excluded from the 
96

NOX SIP Call. Small cogeneration units are units that supply one-third or less of their potential 

electrical output capacity, or 25 megawatts or less, to any utility power distribution system for 

sale. 

The department’s Air Pollution Control Program developed 10 CSR 10-6.360 Control of NOX

Emissions from Electric Generating Units and Non-Electric Generating Boilers, 10 CSR 10-

6.380 Control of NOX Emissions from Portland Cement Kilns, and 10 CSR 10-6.390 Control of 

NOX Emission from Large Stationary Internal Combustion Engines. This set of three rules 

constitutes Missouri’s response to EPA’s NOX SIP Call. These rules were presented at public 

hearing on April 28, 2005 and were adopted at the May 26, 2005 MACC meeting. The state rules 

include schedules for compliance, sources affected by the rule and emissions limitations. Table 

11.3 summarizes the NOX allowances for each unit during the ozone season. 

Table 11.3: NOX SIP Call Emissions Allocation (tons/ozone season) 

County Plant Facility Name Unit ID NOX Allocation 

031 0090 AMEREN – VIADUCT Combustion Turbine 1 4

071 0003 AMEREN – LABADIE Boiler 1 1146

071 0003 AMEREN – LABADIE Boiler 2 1263

071 0003 AMEREN – LABADIE Boiler 3 1449

071 0003 AMEREN – LABADIE Boiler 4 1339

099 0016 AMEREN - RUSH ISLAND Boiler 1 1405

099 0016 AMEREN - RUSH ISLAND Boiler 2 1395

143 0004 AECI - NEW MADRID Boiler 1 1126

143 0004 AECI - NEW MADRID Boiler 2 1182

183 0001 AMEREN – SIOUX Boiler 1 809

183 0001 AMEREN – SIOUX Boiler 2 726

189 0010 AMEREN – MERAMEC Boiler 1 114

189 0010 AMEREN – MERAMEC Boiler 2 88

189 0010 AMEREN – MERAMEC Boiler 3 152

189 0010 AMEREN – MERAMEC Boiler 4 280

189 0010 AMEREN – MERAMEC Unit 5 5

189 0023 AMEREN – HOWARD BEND Combustion Turbine 1 3

201 0017 CITY OF SIKESTON Boiler 1 780

 Energy Efficiency Set-Aside 134

 TOTAL EGU Tons per Ozone Season NOX 13400

 

510 0003 ANHEUSER BUSCH Boiler 6 14

510 0038 TRIGEN ASHLEY STREET Boiler 5 9

510 0038 TRIGEN ASHLEY STREET Boiler 6 36

 TOTAL Non-EGU Tons per Ozone Season NOX 59
97

11.4.2 Additional controls beyond RPG modeling demonstration 

Ongoing air pollution control programs, as described in Section 11.4.1, are sufficient to meet the 

2018 Uniform Rate of Progress for the Mingo and Hercules Glades Class 1 areas. These 

ongoing programs such as CAIR, BACT, or BART have been demonstrated to be very costeffective in reducing the visibility in Missouri’s Class I areas. 

Additional controls not included in the modeling demonstration in the plan may be considered 

during the five-year review. A number of control strategies include SO2/NOX Reasonably 

Available Control Technology (RACT) in the St Louis PM2.5 plan, Illinois Multi-Pollutant 

Strategy, regional SO2 and NOX control strategy proposed by Alpine Geophysics (Alpine) for 

CENRAP. 

11.4.2.1 SO2 and NOX RACT in St Louis

Missouri is in the process of preparing an implementation plan to address the St. Louis PM2.5 

nonattainment problem. In addition to the development of an attainment demonstration, the 

PM2.5 implementation rule requires states to develop all RACT and Reasonably Achievable 

Control Measures (RACM). All non-EGU SO2 and NOX sources were identified in the St. Louis 

PM2.5 nonattainment area that had actual emissions exceeding 25 tons per year. These include 

large boilers, stationary internal combustion engines, two glass melting furnaces, a biosolids 

incinerator, a cement kiln and a lead smelter. The emission reductions associated with these 

sources will be determined and included in the PM2.5 plan. 

11.4.2.2 Illinois Multi-Pollutant Regulation 

In 2006, a multi-pollutant standard (MPS) rule was approved by the Illinois Pollution Control 

Board and the Joint Committee on Administrative Rules. This multi-pollutant rule will result in 

measurable reduction in mercury, SO2, and NOX emissions. The rule targets the three largest 

coal-fired power plant companies in Illinois: Midwest Generation, Ameren and Dynegy. These 

three companies represent 88 percent of Illinois’ 17,007 Megawatts of electric generating 

capacity from coal-fired plants. By implementation of this rule, the Illinois Environmental 

Protection Agency estimates the total emissions reduction from all three power companies is 
98

233,600 tons per year of SO2 and 61,434 tons per year of NOX. This is a drastic improvement 

compared to emissions reduction achieved by the CAIR. 

11.4.2.3 Regional Controls proposed by Alpine Geophysics (Alpine) 

In February 2006, Alpine was contracted by CENRAP to assist in developing control strategies 

for CENRAP Class I areas. Based on the available cost information and the Area of Influence 

(AOI) analyses, Alpine proposed a methodology for constructing control strategy for both EGUs 

and non-EGUs. Control technologies for different industrial source categories were identified. 

Regional “CAIR-like” EGU controls, and sub-regional (AOI region) – Industrial, Commercial, 

and Institutional boilers and natural gas compressors controls – were recommended by Alpine. 

The final report from Alpine can be found in Appendix W. 

11.4.3 Measures to mitigate the impacts of construction activities 

40 CFR 51.308(d)(3)(v)(B) requires Missouri to consider measures to mitigate the impacts of 

construction activities. Under the NAAQS, any nonattainment area in Missouri is required to 

consider construction emissions as part of the general conformity rule. Missouri meets this 

commitment through rule 10 CSR 10-6.300 Conformity of General Federal Actions to State 

Implementation Plans, which can be found in Appendix V. This rule sets forth policy, criteria 

and procedures for demonstrating and assuring conformity to applicable implementation plans. 

11.4.4 Source retirement and replacement schedules 

40 CFR 51.308(d)(3)(v)(D) requires Missouri to consider source retirement and replacement 

schedules in developing RPGs. Retirement and replacement will be managed in conformance 

with existing SIP/TIP requirements pertaining to PSD and New Source Review (NSR). 

11.4.5 Smoke Management Plan 

40 CFR 51.308(d)(3)(v)(E) requires Missouri to consider smoke management techniques for the 

purposes of agricultural and forestry management in developing RPGs. 

The purpose of the Smoke Management Plan (SMP) adopted by Missouri is to identify the 

responsibilities of the Missouri Department of Natural Resources, FLMs, and state land 

managers to coordinate procedures that mitigate the impacts of prescribed fire and wildland fire 
99

used for resource benefits on public health, safety and visibility. This plan is designed to meet 

the policies of the EPA’s Interim Air Quality Policy on Wildland and Prescribed Fires (April 

1998) and addresses smoke management through various procedures and requirements in place 

at various agencies throughout the state. 

The department does not intend to submit the SMP for inclusion in the Missouri SIP, but a copy 

of the Missouri SMP is provided in Appendix X for reference. A letter certifying that the SMP 

meets the basic requirements will be provided to EPA. 

The purpose of a SMP is to mitigate the nuisance and public safety hazards (e.g., on roadways 

and at airports) posed by smoke intrusions into populated areas; to prevent deterioration of air 

quality and NAAQS violations; and to address visibility impacts in mandatory federal Class I 

areas. Some strong indications that an area needs a SMP are: (1) citizens increasingly complain 

of smoke intrusions; (2) the trend of monitored air quality values is increasing (approaching the 

daily or annual NAAQS for PM2.5 or PM10) because of significant contributions from fires 

managed for resource benefits; (3) fires cause or significantly contribute to monitored air quality 

that is already greater than 85 percent of the daily or annual NAAQS for PM2.5 or PM10; or (4) 

fires in the area significantly contribute to visibility impairment in mandatory federal Class I 

areas. None of these four indicators currently shows a problem in Missouri. However, the 

Missouri SMP should provide additional protection to the federal Class I areas. 

11.4.6 Enforceability of Emission Limitations and Control Measures 

40 CFR 51.308(d)(3)(v)(F) requires Missouri to ensure that emission limitations and control 

measures used to meet RPGs are enforceable. 

Missouri has ensured that all emission limitations and control measures used to meet RPGs are 

enforceable by Missouri law through section 643 of the Revised Statutes of Missouri. In 

addition, rules developed for CAIR and the NOX SIP call have placed emission limits on both 

EGU and non-EGU units. These rules can be found in Appendix V. 
100

11.4.7 Anticipated net effect on visibility resulting from projected changes to emissions 

40 CFR 51.308(d)(3)(v)(G) requires Missouri to address the net effect on visibility resulting 

from changes projected in point, area and mobile source emissions by 2018. 

 

The emission inventory for Missouri projects changes to point, area and mobile source 

inventories by the end of the first implementation period resulting from population growth; 

industrial, energy and natural resources development; land management; and air pollution 

control. A summary of these changes is given in Tables 7.1 and 7.2 for each of the pollutants 

addressed in the regional haze plan inventory. 

The net effect on visibility in Missouri Class I areas resulting from these emission differences is 

discussed in the CENRAP Technical Support Document (Appendix F). 

11.5 FIVE-YEAR REVIEW

For the 2013 five-year review process, Missouri intends to conduct a five factor analysis (four 

factors plus visibility impact) to address reasonable progress goals set for Mingo and Hercules 

Glades Class 1 areas. 
101

12.0 COMPREHENSIVE PERIODIC PLAN REVISIONS 

40 CFR 51.308(f) requires a state/tribe to revise its regional haze implementation plan and 

submit a plan revision to EPA by July 31, 2018 and every ten years thereafter. In accordance 

with the requirements listed in section 51.308(f) of the federal Regional Haze Rule, Missouri 

commits to revising and submitting this regional haze implementation plan by July 31, 2018 and 

every ten years thereafter. 

The Missouri Department of Natural Resources Air Pollution Control Program is responsible for 

developing and submitting the required SIP revisions and periodic reports. The plan has been 

developed and will be maintained in electronic (computer) format as well as in paper copy. 

In addition, 40 CFR 51.308(g) requires periodic reports evaluating progress towards the RPGs 

established for each mandatory Class I area. In accordance with the requirements listed in 

Section 51.308(g) of the federal rule for regional haze, Missouri commits to submitting a report 

on reasonable progress to EPA every five years following the initial submittal of the plan. The 

reasonable progress report will evaluate the progress made towards the RPG for each mandatory 

Class I area located within Missouri and in each mandatory Class I area located outside Missouri 

that may be affected by emissions from within Missouri. The report will be in the form of a SIP 

revision. 

 

To establish the criteria in evaluating progress, all requirements listed in 40 CFR 51.308(g) shall 

be addressed in the plan revision for reasonable progress. These criteria are as follows: 

1) Assessment of visibility conditions and changes for each federal Class I area in 

Missouri; 

2) Implementation status of control measures included in plan and a summary of 

emissions reductions achieved from measures; 

3) Analysis of emission reductions by pollutant, identified by source or activity; 
102

4) Assessment of any significant changes in anthropogenic emissions; 

5) Assessment of whether current plan is sufficient to meet RPGs; and 

6) Review of Missouri’s visibility monitoring strategy and any necessary strategy 

modifications 

Figure 12.1 shows a flow chart for 5-year review criteria and actions to be taken if the criteria 

cannot be met. 

All of the required documents (status, summaries, assessments, analysis and reviews will be done 

by the Missouri Department of Natural Resources Air Pollution Control Program. 

no

yes

Regional Haze SIP 5-year Progress Review (2008-2013)

Analyze monitoring data

Analyze emissions data

Are

RPGs being

met?

Submit 5-year progress 

report and a negative 

declaration 

Submit a revised SIP to 

EPA within 1 year of the 

progress report

● QA IMPROVE data from Mingo and Hercules Glade.

● Calculate current visibility conditions for most 

impaired and least impaired days.

● Calculate differences between current conditions 

and baseline conditions.

● Determine whether RPGs are being met.

Notify EPA/FLMS and 

Conduct additional analysis

● Develop 10-year emissions trend (2002-2011) for 

pollutants that contribute to visibility impairment.

● Document emission changes over the 5-year period 

being evaluated, including changes due to 

implemented controls.

● Project emission changes due to planned controls.

● Consider modeling the impact of projected changes 

on visibility and determine whether RPGs are 

expected to be met.

● Notify EPA and other state(s) if impacts are from 

outside the state.

● Consult with other state(s) to develop additional 

strategies.

● Consider applying 4-factor analysis to candidate 

emission reduction strategies.

● Consider modeling of additional controls based on 4-

factor analysis.

Figure 12.1: 5-Year Progress Review Criteria and Actions 
103

13.0 DETERMINATION OF THE ADEQUACY OF THE EXISTING PLAN 

Using the modeling and monitoring as described in this plan, a determination has been made that 

the plan will continue to meet the goal of showing progress towards reducing visibility. Using 

the consultation process described in this plan, Missouri’s visibility goals have been adequately 

addressed. In addition, through participation in other states’ consultation processes, Missouri’s 

contribution to other states visibility goals is being adequately addressed. 

The findings of the five-year progress report as described in Chapter 12.0 will determine which 

action is appropriate and necessary. Depending on the findings of the five-year progress report, 

Missouri commits to taking one of the actions listed in 40 CFR 51.308(h): 

1) If Missouri determines that the existing plan requires no further substantive 

revision in order to achieve established goals, the state will provide the EPA with 

a negative declaration that further revision of the plan is not needed at this time. 

2) If Missouri determines that the existing plan may be inadequate to ensure 

reasonable progress due to emissions from other states that participated in the 

regional planning process, Missouri will provide notification to the EPA and the 

other states that participated in regional planning. Missouri will collaborate with 

the other states through the regional planning process to address the plan’s 

deficiencies. 

3) Where Missouri determines that the current plan may be inadequate to ensure 

reasonable progress due to emissions from another country, the state shall provide 

notification, along with available information, to the EPA. 

4) Where Missouri determines that the existing plan is inadequate to ensure 

reasonable progress due to emissions within the state, Missouri shall revise its 

plan to address the plan’s deficiencies within one year. 

Modeling and monitoring information will be used and the consultation process described in the 

plan will be followed in carrying out the scheduled incremental administrative and technical 

actions required in the plan. Any resulting plan revisions could include a revision to goals, 
104

contingency measures, the monitoring strategy, and any other parts of the plan as deemed 

necessary. 
105

14.0 REFERENCE INFORMATION 

14.1 LIST OF REFERENCES

Caughey, Mike; David Gay, and Clyde Sweet. CENRAP Project Report: Monitoring Ambient 

Ammonia and Related Compounds in the Midwest 2003-2006. Illinois State Water 

Survey. (Champaign, IL): 31 August 2006. 

Missouri Department of Natural Resources. Missouri Statewide Estimates for the 2002 National 

Emissions Inventory (NEI): Area Sources. Missouri DNR. Jefferson City, MO: 8 

January 2007. 

National Research Council. Protecting Visibility in National Parks and Wilderness Areas. 

National Academy Press. Washington, DC: 1993. 

Pace, Thompson G. Methodology to Estimate the Transportable Fraction (TF) of Fugitive Dust 

Emissions for Regional and Urban Scale Air Quality Analyses. 3 August 2005. U.S. 

Environmental Protection Agency. Accessed 26 October 2007 

<http://www.epa.gov/ttn/chief/emch/invent/>. 

Trijonis, J.C. “National Acid Precipitation Assessment Program Report.” State of Science & 

Technology, Vol. III, 1990. 

U.S. Environmental Protection Agency. Emissions Inventory Guidance for Implementation of 

Ozone and Particulate Matter National Ambient Air Quality Standards (NAAQS) and 

Regional Haze Regulations. EPA. Research Triangle Park, NC: August 2005. 

_______. Guidance for Estimating Natural Visibility Conditions under the Regional Haze 

Program. EPA. Research Triangle Park, NC: September 2003. 
106

14.2 LIST OF ACRONYMS AND ABBREVIATIONS

AIRS Aerometric Information Retrieval System 

Alpine Alpine Geophysics 

AOI Area of Influence 

BACT Best Available Control Technology 

BART Best Available Retrofit Technology 

CAA Clean Air Act 

CAIR Clean Air Interstate Rule 

CAMx Comprehensive Air quality Model with Extensions 

CASTNet Clean Air Status and Trends Network 

CEM Continuous Emissions Monitor 

CENRAP Central Regional Air Planning Association 

CFR Code of Federal Regulations 

CHIEF Clearinghouse for Inventories and Emission Factors 

CMAQ Community Multiscale Air Quality 

CO Carbon Monoxide 

department Missouri Department of Natural Resources 

dv deciviews 

EC elemental carbon 

EGU Electric Generating Unit 

EIQ Emission Inventory Questionnaire 

EPA United States Environmental Protection Agency 

FLM Federal Land Manager 

ftp file transfer protocol 

GCVTC Grand Canyon Visibility Transport Commission 

IDA Inventory Data Analyzer 

IMPROVE Interagency Monitoring of PROtected Visual Environments 

IPM Integrated Planning Model 

MACC Missouri Air Conservation Commission 

MACT Maximum Achievable Control Technology 

MM5 Fifth-Generation NCAR / Penn State Mesoscale Model 

MPS Multi-Pollutant Standard 

MRPO Midwest Regional Planning Organization 

NAAQS National Ambient Air Quality Standard 

NCAR National Center for Atmospheric Research 

NEI National Emissions Inventory 

NH3 Ammonia 

NOx Nitrogen Oxides 

NO2 Nitrite 

NO3 Nitrate 

NSPS New Source Performance Standards 

NSR New Source Review 

OMC Organic Mass Carbon 

OMH Organic Mass Hydrogen 

PM Particulate Matter 
107

Pechan E. H. Pechan & Associates 

PMF Fine Particulate Matter 

POG Policy Oversight Group 

ppm parts per million 

PSAT Particulate Matter Source Apportionment Technology 

PSD Prevention of Significant Deterioration 

RACM Reasonably Achievable Control Measures 

RACT Reasonably Available Control Technology 

REMSAD Regional Modeling System for Aerosols and Deposition 

RH Relative Humidity 

RPG Reasonable Progress Goals 

RPO Regional Planning Organizations 

RVP Reid Vapor Pressure 

SEARCH South Eastern Aerosol Research and Characterization 

SIC Standard Industrial Code 

SIP State Implementation Plan 

SMOKE Sparse Matrix Operator Kernel 

SMP Smoke Management Program 

SO4 Sulfate 

SO2 Sulfur Dioxide 

STN Speciated Trends Network 

TIP Tribal Implementation Plan 

TPY Tons Per Year 

UCR University of California-Riverside 

UMC University of Missouri-Columbia 

URP Uniform Rate of Progress 

USDA United States Department of Agriculture 

VIEWS Visibility Information Exchange Websystem 

VISTAS Visibility Improvement State and Tribal Association of the Southeast 

VOC Volatile Organic Compound 

WIMO Wichita Mountains Class I Area 
108

14.3 LIST OF APPENDICES

Appendix A Regional Haze Program Requirements, 40 CFR 51.308 

Appendix B December 6, 2007 and June 25, 2009 Public Hearing Notices 

and Certifications of Publication of the Notice 

Appendix C Comments and Responses to the Plan and 2009 Revision to the 

Plan 

Appendix D MACC Adoption Certifications 

Appendix E Central Class I Areas Consultation Plan 

Appendix F CENRAP Technical Support Document 

Appendix G Revised IMPROVE Algorithm for Estimating Light Extinction 

from Particle Speciation Data 

Appendix H 2002 and 2018 Emissions Inventory 

Appendix I BART-Eligible Emission Point Information 

Appendix J BART Survey and Supplemental Information 

Appendix K CALPUFF/CALPOST Modeling Files 

Appendix L Refined Meteorological and Land Use Data Sources 

Appendix M Screen-Modeling Analyses 

Appendix N Holcim-Clarksville BART Analysis – April 24, 2008 

Appendix O Holcim-Clarksville BART Analysis – June 12, 2008 

Appendix P Holcim-Clarksville BART Analysis – July 24, 2008 

Appendix Q Holcim-Clarksville SO2 Control Cost Evaluation 

Appendix R Holcim-Clarksville BART Draft Consent Agreement – August 

18, 2008 

Appendix S Holcim-Clarksville BART Final Consent Agreement – April 

19, 2009 

Appendix T Guidance for Setting Reasonable Progress Goals under the 

Regional Haze Program 

Appendix U Consultation Meeting Minutes 

Appendix V Applicable State Rules 

Appendix W CENRAP Regional Haze Control Strategy Analysis Plan 

Appendix X Missouri Smoke Management Plan