## 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) 751-48172 This page is intentionally left blank.3 

### TABLE of CONTENTS

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

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

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

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

1.1 F EDERAL R EGIONAL H AZE R ULE .........................................................................................................11 1.2 C LASS I A REAS

............................................................................................................................... ......12

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

2.1 P LAN S UBMISSION

............................................................................................................................... .14 2.2 L EGAL A UTHORITY ..............................................................................................................................1 4 2.3 P UBLIC H EARING N OTICE AND C ERTIFICATION ....................................................................................14 2.4 C OMMENTS , R ESPONSES , AND E XPLANATIONS OF C HANGE .................................................................14 2.5 M ISSOURI A IR C ONSERVATION C OMMISSION A DOPTION C ERTIFICATION ............................................15 2.6 C OMMITMENT TO R EVISE P LAN ............................................................................................................15

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

4.0 PLAN COORDINATION AND CONSULTATION .......................................................................................1 8

4.1 C ENTRAL C LASS I A REAS C ONSULTATION ...........................................................................................18 4.2 O THER S TATE C ONSULTATIONS ...........................................................................................................19

5.0 ASSESSMENT OF BASELINE AND CURR ENT CONDITIONS AND ESTIMATE OF NATURAL CONDITIONS ..................................................................................................................... ......................................25

5.1 V ISIBILITY R EQUIREMENTS ..................................................................................................................25 5.2 B ASELINE V ISIBILITY C ONDITIONS .......................................................................................................27 5.3 N ATURAL V ISIBILITY C ONDITIONS .......................................................................................................29

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

6.1 M ONITORING R EQUIREMENTS ..............................................................................................................30 6.2 C URRENT M ONITORING S TRATEGY ......................................................................................................30 6.3 F UTURE M ONITORING S TRATEGY .........................................................................................................32 6.4 S PECIAL M ONITORING S TUDIES ............................................................................................................33

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

7.1 2002 AND 2018 E MISSIONS I NVENTORY S UMMARY ..............................................................................34 7.2 O VERVIEW OF E MISSIONS I NVENTORY D EVELOPMENT ........................................................................35 7.2.1 Point S ources .................................................................................................................. ................35 7.2.2 Area Sources ................................................................................................................... ................36 7.2.3 Offroad Mob ile S ources......................................................................................................... .........38 7.2.4 Onroad Mob ile So urces .......................................................................................................... ........39 7.2.5 Biogenic Emissions............................................................................................................. ............40 7.3 P ERIODIC U PDATES OF E MISSIONS I NVENTORIES .................................................................................40

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

8.1 M ODELING R EQUIREMENTS ..................................................................................................................42 8.2 M ODEL I NPUTS

............................................................................................................................... ......43 8.2.1 Selection of Episodes.......................................................................................................... ............43 8.2.2 Selection of M odeling Domain ................................................................................................... ....43 8.2.3 Emission Inventories........................................................................................................... ............434 8.2.4 Meteorology.................................................................................................................... ................44 8.3 M ODEL P ERFORMANCE E VALUATION ...................................................................................................44 8.4 B ASE G M ODEL S IMULATIONS .............................................................................................................45 8.4.1 2018 Base G visi bility projections ............................................................................................. .....45 8.4.2 Other RPO’s visib ility proj ections............................................................................................. .....50

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

9.1 BART R EQUIREMENTS .........................................................................................................................51 9.2 BART

– E LIGIBLE S OURCES IN S TATE OF M ISSOURI ............................................................................51 9.3 D ETERMINATION OF S OURCES S UBJECT TO BART...............................................................................54 9.3.1 University of Mi ssouri-Columbia ................................................................................................ ...62 9.3.2 Noranda........................................................................................................................ ...................64 9.3.3 Independence Power and Li ght – Blue Valley................................................................................67 9.3.4 Marshall Munici pal U tilities

................................................................................................... ........68 9.3.5 Columbia Municipa l Power Plant ................................................................................................. ..69 9.3.6 BASF Corporati on - Palmyra..................................................................................................... .....70 9.3.7 Doe Run - Buick ................................................................................................................ .............72 9.3.8 Holcim - Cl arksv ille........................................................................................................... .............73

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

10.1 R EASONABLE P ROGRESS G OAL R EQUIREMENTS ..................................................................................80 10.2 M ISSOURI R EASONABLE P ROGRESS G OAL ...........................................................................................81 10.2.1 Cost and time necessary for co mpliance factor anal ysis by EPA .........................................................81 10.2.2 Cost anal ysis 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 reason able progre ss goals ...................................................................................... ................85 10.3 C ONSULTATION

............................................................................................................................... .....85 10.4 R EPORTING

............................................................................................................................... ............86

11.0 LONG-TERM STRA TEGY TO REACH REASONA BLE PROGRESS GOALS.....................................87

11.1 L ONG -T ERM S TRATEGY R EQUIREMENTS ..............................................................................................87 11.2 C ONSULTATION

............................................................................................................................... .....87 11.3 S HARE OF E MISSION R EDUCTIONS ........................................................................................................87 11.4 L ONG -T ERM S TRATEGY C OMPONENTS .................................................................................................88 11.4.1 Ongoing air pollution control progra ms – “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 NO X SIP Call

............................................................................................................................... ..95 11.4.2 Additional controls beyo nd RPG modeling de monstration .................................................................9 7

11.4.2.1 SO 2 and NO X 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 impact s of constructi on activities............................................................98 11.4.4 Source retirement and replacement schedules.................................................................................98 11.4.5 Smoke Management Plan.......................................................................................................... ......98 11.4.6 Enforceability of Emission Limita tions and Contro l Measur es ......................................................99 11.4.7 Anticipated net effect on vi sibility resulting from projected changes to emissions ......................100 11.5 F IVE -Y EAR R EVIEW ...........................................................................................................................100

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

13.0 DETERMINATION OF THE ADEQ UACY OF THE EXIS TING PL AN ...............................................1035 14.0 REFERENCE INFORMATION.................................................................................................... ...............105

14.1 L IST OF R EFERENCES ..........................................................................................................................105 14.2 L IST OF A CRONYMS AND A BBREVIATIONS .........................................................................................106 14.3 L IST OF A PPENDICES ...........................................................................................................................1086 

### LIST of FIGURES

Figure 3.1: Geographi cal 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 n itrate ma ppings ..................................................................... ..................23 Figure 4.3: PSAT Source Analysis for Missouri modeling demonstration (as part of CENRAP Analysis)...............24 Figure 5.1: Determinati on of Natural Background ............................................................................... ......................26 Figure 6.1: Hercules Glades IMPROVE Monito ring Station ........................................................................ .............31 Figure 6.2: Mingo IMPR OVE Monitoring Station.................................................................................. ...................31 Figure 6.3: El Dorado Springs IMPROVE Protocol Monitoring Station ............................................................. ......32 Figure 8.1a: 2018 Visibility Projections and 2018 URP G lidepaths 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 G lidepaths 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 G lidepaths in deciview for Mingo, Missouri, and Best 20% days using 2002/2018 Base G CM AQ 36 km modeling results. ....................................................................... ..49 Figure 12.1: 5-Year Progress Review Criteri a and Ac tions...................................................................... ................1027 LIST of TABLES Table 5.1: Baseline Visibility Cond itions for Missouri Class I Areas.......................................................... ..............28 Table 5.2: Natural Background Conditi ons for the Class 1 Areas in Missouri.................................................... .......29 Table 7.1: 2002 Missouri Em issions Inventory Summary.......................................................................... ................34 Table 7.2: 2018 Missouri Em issions Inventory Summary.......................................................................... ................34 Table 9.1: Facilities with BART-eligib le Units in the St ate of Mi ssouri....................................................... .............52 Table 9.2: Units Removed from BART Consideration Due to Shutdown or Federal Permit Requiring Shutdown ...55 Table 9.3: CALPUFF/CA LPOST Screen ing Re sults .................................................................................. ...............58 Table 9.4: Number of Days ove r the 0.5 Deciview Threshold ..................................................................... ..............60 Table 9.5: Grid Structure for Refined Te rrain, Land Use, an d CALMET Analyses .................................................. 62 Table 9.6: UMC Refined Analysis Re sults (Boiler PM Sp eciation Pr ofile)........................................................ .......63 Table 9.7: UMC Refined Analysis Results (PM 10 =PMF) Method 2 ..........................................................................63 Table 9.8: UMC Refined Analysis Results (PM 10 =PMF) Method 6 ..........................................................................63 Table 9.9: Noranda Refined Analys is Results (Origi nal Submittal).............................................................. .............66 Table 9.10: Noranda Refined Anal ysis Results (Rev ised CALMET) ................................................................. .......67 Table 9.11: Independence Power an d Light Refined An alysis Results ............................................................. .........68 Table 9.12: Marshall Municipal Utilities Refined An alysis Results............................................................. ..............69 Table 9.13: Columbia Municipal Utilities Refined An alysis Results ............................................................. ............70 Table 9.14: BASF Corporatio n Refined Anal ysis Re sults......................................................................... .................72 Table 9.15: Doe Run Buick Refined Sensitiv ity Re sults......................................................................... ...................73 Table 9.16: Holcim - Clarksv ille Refined Anal ysis Re sults ..................................................................... ..................74 Table 9.17: Holcim - Clarksville Po st-Submittal Refined Analysis Results...................................................... .........75 Table 9.18: Holcim - Clarksville BA RT Limit Refined Analysis Results.......................................................... ........77 Table 10.1: Uniform Rate of Progress and Reasonab le Progress Goals for Cla ss I areas in Missouri .......................85 Table 11.1: CAIR NO X Emissions Allocation (tons/yr) .............................................................................................90 Table 11.2: CAIR SO 2 Emissions Alloca tion (tons/yr) ..............................................................................................92 Table 11.3: NO X SIP Call Emissions Allocati on (tons/ozone season)........................................................................968 

### EXECUTIVE SUMMARY

In 1977, Congress passed amendments to the Cl ean Air Act (CAA) with the goal of improving visibility in Class I federal areas, such as na tional parks and wilderness areas. Following the enactment of the 1977 CAA amendments, some measur es 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 additiona l amendments to the CAA in 1990

that authorized additi onal research and regular progress updates.

The U.S. Environmental Protection Agency (E PA) 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 Mana gers (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 contro ls for regional haze. This consultation process will provide a coordinated effort to achieve th e federal visibility requirements and aid in developing regional strategies for meeting progress goals.

The Regional Haze Rule went into effect on A ugust 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, includi ng Missouri. Missouri has two fe deral Class I areas (Hercules Glades and Mingo) within its bo rders 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 da ta 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 Mi ssouri will meet the 2018 Reasonable Progress Goal (RPG). The analyses in this Regional Haze Plan demonstrate that the 2018 visibility goals for9 Mingo and Hercules Glades will be largely achieved from E GU (Electric Generating Unit) emission reductions resulting from the federal Clean Air Interstate Rule (CAIR) program. Missouri long-term strategy also consists of othe r air pollution programs including Missouri

NO X State Implementation Plan (SIP) call, Tier 2 vehicle emission standards, other states’ SIP controls, other states’ Best Av ailable 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 consul tation requirement of the fede ral Regional Haze Rule through the consultation process that was used to deve lop this plan. The c onsultation 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 appe ndix to this plan. In addition, Missouri has

consulted with and continues to consult with ot her states that have in cluded Missouri in their consultation process to meet their Re gional Haze Rule requirements.

A BART analysis was used to assure that the fe deral Regional Haze Rule requirements were met. This analysis included BART source devel opment, screen-modeling analyses and refined modeling. As a result of the analysis and m odeling, Missouri has identif ied one BART-eligible

source in Missouri that must unde rgo a BART control evaluation to ensure it meets the Regional Haze Rule requirements.

The Missouri Department of Natural Resources (d epartment) 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 coordi nate with other states, FLMs, EP A, CENRAP, and other RPOs to10 maintain/improve the visibility in Missouri’s Cla ss I areas. This coordination will include fiveyear progress reports and any necessary SIP revisi ons. If deemed necessary, there will be face to face consultation meetings.11 

### 1.0 BACKGROUND - FEDERAL RE GIONAL HAZE REGULATION

1.1 F EDERAL R EGIONAL H AZE R ULE In amendments to the CAA in 1977, Congress a dded 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 th e visibility problems in Class I areas. The control measures taken mainly ad dressed plume blight from specific pollution

sources and did little to address re gional 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 smokestac k, 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, Congre ss added Section 169B (42 U.S.C. 7492), authorizing further research and regular assessmen ts of the progress made so far. In 1993, the National Academy of Sciences concluded that “c urrent scientific knowledge is adequate and control technologies are availabl e for taking regulatory action to improve and protect visibility.” 1

In addition to authorizing crea tion of visibility transport co mmissions and setting forth their duties, Section 169B(f) of the CAA specifi cally 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 Nationa l 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 Nati onal Parks and Wilderness Areas . National Academy Press. Washington, DC: 1993.12 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 nati onal visibility goals by 2064. This rulemaking

addressed the combined visibili ty 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 ag ainst EPA’s Regional Haze Rule of 1999. The Court remanded to EPA the BART provisions of th e 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 faci litate the review of this SIP submittal by the EPA, FLMs, stakeholders, and the pub lic; a guide is provided in 40 CFR 51.308, Regional Haze Program Requirements (Appendix A).

1.2 C LASS I A REAS The State of Missouri has the followi ng Class I areas within its borders:

Hercules Glades Wilderness Area

Situated in southwest Missour i, Taney County, Hercules Glad es Wilderness Area (Hercules Glades) is managed by the United States Departme nt of Agriculture (USDA) Forest Service as part of the Mark Twain National Forest. The area includes 12,315 acres locat ed 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, al ong the Mississippi Flyway. Only a portion of the13 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 th e largest urban areas nearby, a lthough 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 iden tified 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 contribut e to visibility impairment in other states’ Class I areas, such as the Caney Creek and Uppe r Buffalo Wilderness Areas in Arkansas (Upper Buffalo).

Improved visibility will lead to greater enj oyment of recreational opportunities at Hercules Glades and Mingo. The tourists drawn to the sc enic beauty and recrea tional opportunities of each of these areas provide revenue to the re spective regions. Missouri expects improved visibility of Hercules Glades and Mingo to provi de not only enhanced scenic beauty, but also improved health benefits for people who are more susceptible to respiratory problems.14 

### 2.0 GENERAL PLANNING PROVISIONS

2.1 P LAN S UBMISSION 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 re quirements 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 contai ns a commitment to provide plan revisions and adequacy determinations. Missouri has adopted this plan su bmittal in accordance with state laws and rules.

2.2 L EGAL A UTHORITY The MACC is granted the legal authority to de velop and implement regulations regarding air pollution under section 643.050 of th e Revised Statues of Missouri.

2.3 P UBLIC H EARING N OTICE AND C ERTIFICATION The department’s Air Pollution Control Program is required to announce a public hearing at least 30 days prior to holding such a hearing. Announcem ents were submitted to newspapers at least 30 days prior to the public hearing. The public h earing for this Regional Haze Plan occurred on December 6, 2007 and the public hearing for the re vision 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 C OMMENTS , R ESPONSES , AND E XPLANATIONS OF C HANGE Attached in Appendix C are th e 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, se ven days after the Pub lic Hearing that was held on June 25, 2009. The department’s Air Poll ution Control Program is required to respond15 to all comments received by either amending the plan or explaining the reasoning for not making

an amendment.

2.5 M ISSOURI A IR C ONSERVATION C OMMISSION A DOPTION C ERTIFICATION Attached in Appendix D are the MACC adoption cer tifications to demonstrate the approval of the Regional Haze Plan by the Commission.

2.6 C OMMITMENT TO R EVISE P LAN Consultation between the states and the FLMs will continue as the federal regional haze program progresses. The consultation wi ll 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 wi ll also provide for consideration of any other programs that are implemented and have the potential to contribute to impair ment of visibility in

Class I areas.16 

### 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 th e 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 Over sight Group (POG). The POG is made up of 18 voting members representing the states and tr ibes 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 co mmunication 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 is17 accomplished through five standing workgroups: Monitoring; Emission Inventory; Modeling; Communications; and Implementati on and Control Strategies. Participation in workgroups is open to all interested parties. Ad hoc workgroup s 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 reduc tion strategies for improving vi sibility 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 analys is, modeling results and other tec hnical support documents prepared for CENRAP members. By coordinating with CENRAP and other RPOs, Missouri has worked to ensure that its long-term strategy provides su fficient reductions to mitig ate impacts of sources

from Missouri on affected Class I areas. Data analyses, modeling result s and other technical support documents are provided to CENRAP memb ers through either CENRAP’s website or through a file transfer protocol (f tp) that allows users to copy file s between their lo cal system and CENRAP’s system that they can reach on the CENRAP network.18 

### 4.0 PLAN COORDINATION AND CONSULTATION

4.1 C ENTRAL C LASS I A REAS C ONSULTATION 40 CFR 51.308(i) requires coordi nation 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 CENR AP 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 accord ance with the provisions of 51.308(i)(2).

Missouri provided FLMs an opportunity for consu ltation and an opportunity to hold a face to face meeting, if deemed necessa ry. 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 th e 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 im plementation of strategies to address visibility impairment.

According to 40 CFR 51.308(d)(3)(i), Missouri is required to consu lt with other states/tribes to develop coordinated emission strate gies. This requirement applies both when emissions from the state are reasonably anticipated to contribute to visibility impairme nt in Class I areas outside the

state and when emissions from other states/tribe s are reasonably anticipated to contribute to visibility impairment in Class I areas within the state.

Missouri has consulted with othe r states/tribes in CENRAP, Visi bility Improvement State and

Tribal Association of the S outheast (VISTAS), the Midwest Regional Planning Organization (MRPO), FLMs and EPA Regions 5, 6 and 7 on de velopment of coordinated strategies for19 Central Class I areas, including Mingo, Hercul es 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 dete rmine 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 he aring would be held on this pl an 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 provi ded 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 propos ed controls through both state and federal requirements. It was also determined that th ese RPGs will meet the established URP goals by 2018. The consultation process determined which st ates significantly impacted the Arkansas and

Missouri Class I areas.

Missouri is reasonably anticipated to c ontribute 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 FL Ms 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 O THER S TATE C ONSULTATIONS The consultation processes for the Wichita M ountains (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, Mi ssouri replied with a letter recommending that the rationale for determining contributing states deserves further examination. A more inclusive20 methodology for the Central Class I areas with f our 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 dist ance 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 th at planned emission controls on Missouri sources would be significant enough. It seems likely that Missouri would not be in cluded 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 Pollu tion Control Agency indi cated that it believes that Missouri impacts the Boundary Waters, but not Voyageurs.

Minnesota identified Missouri as a contributi ng state based on LADCO 2002-2003 Trajectory analysis or LADCO 2018 PSAT mode ling 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 Study 2 shows emissions for the northern Class I area at Voyageurs National Park indicatin g the high impact of Minnesota sources, with

2 Causes of Haze II, 2005; Sullivan, Ha fner, Brown, MacDonald, Raffuse, Pe nfold, Roberts, Sonoma Technology21 only small impact by out of state sources. Voyage urs and the Boundary Wate rs are very close in proximity, and the overall analysis was intende d 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 gr eater result than controls on sources outside Minnesota. Comparisons with Herc ules Glades EIP show the difference in areas with significant external sources (Hercules) to areas with si gnificant internal sour ces (Voyageurs, Boundary Waters). The conclusion reached in the Caus es of Haze II is that for Voyageurs, and by geographic proximity, Boundary Waters, importa nt emission source regions are internal (Minnesota and to a lesser exte nt North Dakota) on the 20 percent worst days. Area of Influence analysis for CENRAP states confirms that Le vel 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 th an 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 res ponse to Minnesota regarding the Northern Class I Areas

consultation.

Since other states are still invo lved 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 mappings23 Figure 4.2: Causes of Haze Study II, EIP nitrate mappings24 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 V ISIBILITY R EQUIREMENTS 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 natura lly occurring phenomena that redu ce visibility as measured in terms of light extinction, visual range, contrast, or coloration.” The regional haze plans must contain measures that make “reasonable prog ress” toward this goal by reducing anthropogenic emissions that cause haze. For each Class I area, th ere are three metrics of vi sibility 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 concentrati on 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 wh en 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 in itial baseline conditions to natural visibility conditions indicates the amount of improvement n ecessary 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 th e light extinction algorith m (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 Regiona l Haze Rule. As part of a “long-term strategy” for regional haze, a stat e 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 aff ect 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 c onsultation on reasonable progress goa ls and long-term strategies, which are based on the current (baseline) and natura l 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 vi sibility conditions in

each of the Class I areas. 

## Example: Rate that Would Achieve Natural Conditions in 60 Years27 In addition, states in CENRAP have conferre d with neighboring Class I area states outside CENRAP, both individually a nd by way of the states’ RPO.

Sec. 51.308(i) requires Class I ar ea states’ coordination with FL Ms 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 st ate, 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 B ASELINE V ISIBILITY C ONDITIONS During the five-year (2000-2004) baseline period, s ites are required to have three valid years of

data from which baseline conditions can be cons tructed. The Visibility Information Exchange Websystem (VIEWS) website ( http://vista.cira.col ostate.edu/views/ ) has posted particulate matter (PM)-species specific natural and baseline conditi ons based on the new IMPROVE algorithm. The new IMPROVE algorithm was developed by fitting reconstructed light

extinction based on IMPROVE m easured PM and nitrite (NO 2 ) concentrations with actual colocated measured light extinction (e.g., nephe lometer measurements. The VIEWS document, Revised IMPROVE Algorithm for Estimating Light Extinction from Particle Speciation Data

, posted under gray literature, explai ns the justification for the use of the ne w equation. Section II of this algorithm document, which provides mo re detail on the revised IMPROVE equation is included as Appendix G. The c hoice 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 st ate will make the determin ations of baseline and natu ral visibility conditions.28 projections using the new IMPROV E equation to calculate visibili ty metrics for the purpose of developing its reasonable progress go al (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 Unifor m Rate of Progress (URP) goal on a species-by-species ba sis in accordance with 40 CFR 51.308(d)(2).

The Mingo Class I area has an established baseli ne visibility of 13.76 dv for the cleanest 20 percent of the sample days and 28.02 dv for the 20 pe rcent worst visibility days, as indicated in Table 5.1. This is based on sampling data co llected at the Mingo IMPROVE monitoring site, which was established by the IMPROVE sampling st aff 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 resoluti on 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 suffi cient data so that three-years of valid data

were available from which baseline conditions co uld be calculated. The data filled IMPROVE database were prepared and ma de 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 esta blished 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 th e Hercules Glades IMPROVE monitoring site which was established by the IMPROVE sampling st aff at the University of California-Davis via their protocols.

Table 5.1: Baseline Visibility Co nditions 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 12.8429 5.3 N ATURAL V ISIBILITY C ONDITIONS EPA’s “Guidance for Estimating Natural Vi sibility Conditions Under the Regional Haze Program” (Sept 2003) provides states a “default” estimate of natural visi bility. 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 th e CENRAP states into “East” (MN, IA, MO, AR, and LA), with seven Class I areas, and “West” (NE, KS, OK, a nd TX), with three Class I areas. In the two equations, only sulfate (SO 4 ) and organic carbon have different values, but the calculated dv difference is significant (see Appendix F, Secti on 4.2 for further discussion of the default equation).

Using the New IMPROVE equation, Missouri has de termined that natural visibility conditions for the Mingo Class I area is best represente d 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 Condition s 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 degradation30 

### 6.0 MONITORING STRATEGY

6.1 M ONITORING R EQUIREMENTS 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 Stat e of Missouri. The monitoring strategy relies upon participation in the IMPROVE network.

6.2 C URRENT M ONITORING S TRATEGY Upon the creation of CENRAP, the newly form ed Monitoring Workgroup identified large visibility data voids in Southern Arkansas, Io wa, Kansas, Southern Minnesota, Nebraska, and Oklahoma. Only five IMPROVE sites were lo cated in the CENRAP region. Between 2000 and 2003, five more IMPROVE sites and 15 IMPROVE prot ocol sites were installed. In Missouri,

IMPROVE Sites are located at Hercules Gl ades 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 ar e 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 VIEW S website. This fulfills Missouri’s reporting requirement of visibility data (e lectronic) 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 Station32 Figure 6.3: El Dorado Springs IMPROVE Protocol Monitoring Station

6.3 F UTURE M ONITORING S TRATEGY 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 regi onal 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 Mi ssouri Class I areas will be evaluated during the Missouri five-year review. The five-yea r review will include the following aspects:

 QA IMPROVE data from Mi ngo and Hercules Glades.

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

 Calculate differences between curren t conditions and baseline conditions.

 Determine whether RPGs are being met.

Missouri will also evaluate tec hnology changes and the need for new monitors as appropriate.33 6.4 S PECIAL M ONITORING S TUDIES Special monitoring in the CENRAP region fo r ammonia was conducted from November 1, 2003 through June 28, 2006. In all, approximatel y 7,200 individual ammonia and associated measurements were attempted in the course of th is project. One of the primary outcomes of this sampling was the disclosure that high concentr ations of ammonia are occurring in the northern and central CENRAP regions with a considerable re gularity. It seems likely that these are due to the agricultural sources that have been documen ted 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. (Cha mpaign, IL): August 31, 2006. A copy of the report is available from David A. Gay, As sociate Research Scientist, Illinois State Water Survey, University of Illinois, 217-244-0462.34 

### 7.0 EMISSIONS INVENTORY

7.1 2002 AND 2018 E MISSIONS I NVENTORY S UMMARY As specified in the EPA guidance document , Emissions Inventory Gu idance 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 (NO x ), sulfur dioxide (SO 2 ), volatile organic compounds (VOCs), fine particulate (PM 2.5 ), coarse particulate (PM 10 ), and ammonia (NH 3 ). 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 NO X (TPY*) SO 2 (TPY) PM 10 (TPY) PM 2.5 (TPY) CO (TPY) VOC (TPY) NH 3 (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 NO X (TPY) SO 2 (TPY) PM 10 (TPY) PM 2.5 (TPY) CO (TPY) VOC (TPY) NH 3 (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 Unit35 7.2 O VERVIEW OF E MISSIONS I NVENTORY D EVELOPMENT 7.2.1 Point Sources The 2002 point source inventory is based on in formation 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 ag encies 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 complete d 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 Ai r Pollution Control Program to make corrections where needed. In particular, an error that resulted in the doub le counting of emissions from a

number of emission units was corrected. Th e problem affected VOC emissions only. For example, for the Chrysler-North facil ity (291890231), emission unit number 20949, which emitted a total of 112 tons/year (about 0.3 tons/d ay) VOC in 2002, was associated with stack numbers 44387 and 44388. Instead of being propor tioned 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 nonattainmen t area by a total of 751 tons/year (roughly 2 tons/day). Other revisions incl uded corrections to facility coordinates and stack parameters. Pechan also converted th e point source inventory to the Sparse Matrix Operator Kernel Emissions/Inve ntory 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 gr owth and control factors using the SMOKE36 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 NO X SIP Call for industrial boilers. In additi on, the newly permitted Holcim cement kiln in Ste. Genevieve County was added to the 2018 non-EGU point inventory.

The Integrated Planning Model (IPM) versi on 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. S ee the Pechan report, Refinement of CENRAP’s 2002 Emissions Inventories (August 31, 2005), in Appendix H.3 for more information. The proprietary IPM model ha s been used by the EPA to simulate electrical power generation and electrical power di stribution 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 c ontract to the RPOs. This run corresponds with the “VISTASII_PC_1f” modeling run. This run specifically

addressed the emission reductions to be reali zed through implementation of CAIR assuming all states participate in the EPA’s trading program, Acid Rain Program (Title IV – Phases I and II),

NO X SIP Call, and state and local regulations, wh ile incorporating unit-le vel updates provided by power company stakeholders.

The University of California-Riverside (U CR) ran the SMOKE model for 2018 point source emissions. The edited IPM file for EGUs was pr ocessed in SMOKE without adjustments. The growth and control factors for non-EGUs were a pplied using the SMOKE model. The technical support document in Appendix F describes U CR’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 remaini ng 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 Pollution37 Control Program, the data and methods used are described in the document Missouri Statewide Estimates for the 2002 National Emissi ons Inventory (NEI): Area Sources (January 8, 2007) in Appendix H.5. The data and methods used to de velop the prescribed burning, agricultural dust, and soil agricultural ammonia inventories for CE NRAP can be found in the following reports prepared by Sonoma T echnology in Appendix H: Research and Development of Planned Burning Emission Inventories for the Centra l 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 F actors (CHIEF) website at http://www.epa.gov/ttn/chie f/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. Pech an’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 Regi onal and Urban Scale Air Quality Analyses (Pace 2005).

The 2018 area source emissions inventory was base d 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 201838 Emissions Draft Technical Support Document (M ay 2005). The control factors reflect New Source Performance Standards (NSPS) for resi dential wood combusti on and Stage II vapor recovery controls, includi ng onboard vapor recovery.

UCR ran the SMOKE model for the 2018 area source em issions. The growth and control factors for area sources were applied within SMOKE. The technical support document in Appendix Fdescribes UCR’s work on the 2018 area source inventory. Windblown dust from nonagricultural land use categories and fire emi ssions 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 rema ining gaps filled in with EPA NEI data. Table H.10 in Appendix H.1 lists the source of th e 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, consolid ated 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 fu el 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 inventor y was based on inputs from CE NRAP states. Growth and control factors for locomotives, aircraft, and commercial marine vessels were prepared by

Pechan. The control factors accounted for federa l standards for commercial marine vessels and locomotives. For the remaining offroad m obile categories, Pechan ran the EPA’s39 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 exha ust emission standards fo r large spark-ignition engines, diesel marine, and land- based recreational engines. Pech an’s methods are described in greater detail in the following report in Appendix H.4: Develo pment of Growth and Control Inputs for CENRAP 2018 Emissions Draft Technical Support Do cument (May 2005).

UCR and applied the growth and control fa ctors 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 Progr am and CENRAP, with contractor support, developed the 2002 and 2018 onroad mobile source emissions inventories. Sonoma Technology provided 2002 VMT data and MOBILE6 input file s for all counties in the CENRAP region. MOBILE6 input files were provided only for th e 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 Sour ces 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 usi ng the MOBILE6 model within the SMOKE

framework.

Pechan prepared the VMT and MOBILE6 input s for the 2018 onroad mobile source emissions inventory. The VMT growth f actors and MOBILE6 input files were provided in SMOKE format. The MOBILE6 input files incorporat ed state/local control program information, including Reformulated Gasoline and the inspect ion and maintenance program in the St. Louis nonattainment area and low Reid vapor pressure (R VP) 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 conditi ons and one representing January conditions. Pechan’s methods are described in greater de tail in the following repor t in Appendix H.4:40 Development of Growth and Control Inputs fo r CENRAP 2018 Emissions Draft Technical Support Document (May 2005).

UCR prepared MOBILE6 input files for the re maining months of 2018 and processed the 2018 onroad mobile emissions by running the MOBILE6 model within the SM OKE framework. The SMOKE model applies the VMT growth factor s. The MOBILE6 model accounts for federal motor vehicle controls, including light-duty moto r vehicle engine standards and low-sulfur gasoline, and the federal heavy-dut y diesel engine standards and lo w-sulfur diesel. The technical support document in Appendix F describes U CR’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 fo r deriving emissions estimates of biogenic gasphase pollutants from land use information, emissi ons factors for different plant species, and hourly, gridded meteorology data. Biogenic emi ssions were held constant from 2002 to 2018. The technical support document in Appendix F describes the development of the biogenic emissions inventory.

7.3 P ERIODIC U PDATES OF E MISSIONS I NVENTORIES Recognizing the importance of maintaining current, valid emissions information, the department’s Air Pollution Control Program co mmits 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 update d 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 emi ssions inventory reporting requirements.

In addition to completing regular updates of Missouri’s emissions inventory, the Air Pollution Control Program commits to peri odically reviewing emissions in formation 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 geogr aphic distribution of emissions. The periodic

reviews will be coordinated with other states an d consultation partners and will be conducted in conjunction with the five-year progre ss reports discussed in section 2.6.42 

### 8.0 MODELING ASSESSMENT

8.1 M ODELING R EQUIREMENTS 40 CFR 51, Appendix W provides modeling guidel ines 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 visibi lity: Community Multiscale Air Quality (CMAQ), Comprehensive Air quality Model with extensio ns (CAMx), and Regional Modeling System for Aerosols and Deposition (REMSAD). CENRAP c ontractors performed regional modeling using CMAQ and CAMx.

The CMAQ Model is an Eulerian model that si mulates the atmospheric and surface processes affecting the transport, transformation and deposi tion 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 ma y 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 in corporates all of the technical attributes demanded of state-ofthe-art photochemical grid models, including tw o-way grid nesting, a subgrid-scale Plume-inGrid module to treat the early disper sion and chemistry of point source NO X plumes, and a fast chemistry solver.

In the July 1, 1999 publication of the Regional H aze 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 area43  Analyses to compare visibility improvem ent between proposed control strategies

8.2 M ODEL I NPUTS 8.2.1 Selection of Episodes The calendar year 2002 was selected for the ba se year for CENRAP regional haze annual modeling consistent with EPA guidance. The Technical Support Docume nt 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 m odeling 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 Suppo rt Document provides additional information on the modeling domain and is found at Appendix F.

8.2.3 Emission Inventories The emissions inventory includes VOC, NO X , CO, SO 2 , PM 10 , PM 2.5 , and NH 3 emissions from all anthropogenic and biogenic sources. The emi ssions inventory information submitted by state, tribal, and local agen cies 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, on road and offroad mobile sources, agricultural tilling and livestock dust, and ag ricultural ammonia. In addition, Pechan assisted CENRAP by quality-assuring the emissions inventory and pr eparing day- and hour-specific emissions for

EGUs based on Continuous Emissions Monito r (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 emi ssions inventory consists of se veral 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 modeli ng domain, which covers44 the continental U.S. plus portions of Canada and Mexico. The invent ory was refined through several rounds of CENRAP workgroup review a nd revision, beginning with the initial Base A version and culminating in the Base G inventor y. The Technical Suppor t Document provides the methodologies for the SMOKE emissions processing and is found at Appendix F. A summary of the development of the emissions in ventory 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). Si nce 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-memor y machines, (iv) a four-dimensional dataassimilation capability, and (v) more physics op tions. 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 th e model is integrated. The Technical Support Document provides the methodologies for th is process and is found at Appendix F.

8.3 M ODEL P ERFORMANCE E VALUATION 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 agai nst ambient measurements of PM species, gas-phase species and wet depos ition. Numerous iterations of CMAQ and CAMx 2002 base45 case simulations and model performance evaluati ons 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.e du/aqm/cenrap/cmaq.shtml ) and presented in previous reports and presentations for CENRAP. In general, th e model performance of the CMAQ and CAMx

models for SO 4 and elemental carbon (EC) was good. Model performance for nitrate (NO 3 ) was variable, with a summer underestimation and wint er overestimation bias. Performance for OMC was also variable, with the inclusion of the S econdary Organic Aerosol Modules enhancement in CMAQ Version 4.5 greatly improving the CMAQ su mmer 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 loca l 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 T echnical Support Document in Appendix F.

8.4 B ASE G M ODEL S IMULATIONS 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 th at 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 tr ading program. In addition, reductions anticipated from BART controls for EGUs in Oklahoma, Arkansas, Kans as, 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 mode ls, respectively, which refl ected emissions reductions

from the Tier 2 and Tier 4 mobile source rule s. 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-yea r 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 20 18 levels from which 2018 visibility estimates were obtained. The CENRAP 2018 visibility co nditions were calculated following EPA default46 visibility projection procedures and are labeled “Method 1 Pred iction” 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 si mulate 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 relati ve reduction factors (RRFs) for each of the six components of light extinction in the IMPROVE equation (SO 4 , NO 3 , 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 extincti on was computed using the new IMPROVE equation and the projected PM concentra tions for each of the worst and best 20 percent days in the five-y ear 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 extincti on 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 wo rst and best 20 percent days. 6. The five years of deciview visibility were averaged to obt ain 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 Progre ss (URP) glidepath or the “2018 URP point.” The 2018 URP point is obtained by constructing a linear visi bility glidepath in

deciviews from the observed 2000-2004 Baseline for the worst 20 percent days to the 206447 Natural Conditions. The 2018 URP point is wher e 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 visi bility 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 th e 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 visibili ty projections based on the Base G modeling

results is summarized in 4.4. of the Technical Support Document (T SD), which indicates that Appendix D of the TSD provides de tails for each Class I area in the CENRAP region using the new IMPROVE equation.48 Figure 8.1a: 2018 Visibilit y Projections and 2018 URP Glidepaths in deciview fo r 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 YearHaziness Index (Deciviews)

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

Figure 8.1b: 2018 Visibility Projectio ns and 2018 URP Glidepaths in deci view 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 Prediction49 

### 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 YearHaziness 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 YearHaziness Index (Deciviews)

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

Figure 8.2b: 2018 Visibility Projections and 2018 URP G lidepaths 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 Misso uri Class I areas are al so available from the VISTAS and MRPO modeling. At Hercules Glades, the three RP Os’ 2018 visibility projections are in close agreement with each other, esti mated 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 per cent, respectively. However, the MRPO 2018 visibility projections are approximately 15 pe rcentage points lower than the CENRAP and VISTAS projections at Mingo. The reasons why the MRPO 2018 vi sibility projections are less optimistic than CENRAP and VISTAS are unclear. The discrepancy could be due to the use of

different emissions inve ntories. CENRAP's Base G inve ntory included IPM 2.1.9 results for 2018 EGU emissions that had been quality-assure d and edited by CENRAP and VISTAS states and stakeholders, while MRPO's latest modeli ng inventory used IPM 3.0 results that did not

include edits from VISTAS or most of the CE NRAP states. The department’s Air Pollution Control Program concluded that CENRAP projec tions for Mingo and Hercules Glades should be

more accurate due to a better emissions inventor y for our states. Additional analysis including

the IPM 3.0 results with states’ review will be considered duri ng the five-year review period.51 

### 9.0 BEST AVAILABLE RETR OFIT TECHNOLOGY (BART)

9.1 BART R EQUIREMENTS The EPA’s 1999 Regional Haze Rule singles out cer tain older emission sources that have not been regulated under other provision s of the Clean Air Act for addi tional controls. Older sources that contribute to visibility impairment in Cla ss I areas are required to implement BART or an emissions trading or other alternative program th at will achieve greater reasonable progress than would be achieved through the installation a nd operation of BART. On July 6, 2005, EPA published a revised final rule, including A ppendix 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 in stall BART and how to determine BART.

Based on comments received from EPA Region V II, sources originally not included in the BART air quality review were re-examined. So me additional sources were found to be BART eligible and were evaluated in th e same fashion as the original sources. Upon completion of the BART air quality screen and dr aft refined modeling analyses; the State of Missouri has found one source that is subject to BART. This s ource (Holcim – Clarksvill e) 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 sour ces were found to be subject to BART and, therefore, implementation of an emissions trad ing program, other emission controls or other alternative measure in place of BART are not necessary.

9.2 BART

– E LIGIBLE S OURCES IN S TATE OF M ISSOURI The facilities with BART-eligib le units in the State of Mi ssouri are shown in Table 9.1 (including the newly identified sources). A deta iled description of each BART-eligible emission unit is included in Appendix I.52 Table 9.1: Facilities with BART-elig ible 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 SO 2 and NO X ** Other supporting units listed in faci lity summary later in this section Italics means BART-eligible source identified after EPA comments53 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 BA RT-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 emissi on 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: SO 2 , NO X , and PM 10 .

The Guidelines recommend addressing thes e visibility-impairing pollutants: SO 2 , NO X , and particulate matter. The State of Missouri addres sed these three pollutant s and used particulate matter less than 10 microns in diameter (PM 10 ) as an indicator for part iculate matter to identify BART-eligible units, as the Guidelines suggest. Consistent with the Guidelines, the State of

Missouri did not evaluate emissions of VOCs a nd ammonia in BART determinations for these

reasons: 1) the majority of VOC emissions in Missouri ar e biogenic in nature and specifically the areas near Mingo and Hercules Glades are ve ry rich in biogenic emissions (limited ability to reduce organic concentr ations at the Class I areas), 2) the largest areas of anth ropogenic 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 subs tantial, uncontrolled VOC emissions is charcoal kilns, the department required exis ting 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 un certain and the amount of anthropogenic emissions at the sources that were BART-eligible was relatively small, and54 5) No additional sources were identified that had greater than 250 tons per year ammonia and required a subse quent BART analysis.

The State of Missouri identified potentially BA RT-eligible source by reviewing the emission inventory database and extracting da ta for facilities within the 26 ca tegories identified. A survey was conducted for the facilities within this gr oup 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 (SO 2 , NO X , and PM 10 ), the sources were also asked to identify ammonia and VOC emissions. The survey a nd resultant tabular response information are contained in Appendi x J and Appendix I, respectively.

9.3 D ETERMINATION OF S OURCES S UBJECT TO BART Upon completion of the survey, the BART-eligible sources were divided into four distinct groups: (1) electric generating uni ts participating in the CAIR tr ading program, (2) sources that have final new source review (construction) pe rmits requiring a BART-e ligible 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 ot her 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 E GUs) was modeled collec tively using all BARTeligible sources for only the PM impacts on the applicable Class I areas (NOTE: After EPA comment, two additional CAIR EGU facilities we re discovered to be BART-eligible and additional analysis was performed). All th e sources in the fourth group were modeled independently. The second group included some or all of the BART-eligib le sources at four installations. River Cement, Doe Run – Glover, Continental Cement, a nd Mississippi Lime all had units that were part of a voluntary shutdown or being remo ved due a specific construction permit condition. To be clear, the Doe Run – Gl over facility does not have a current operating permit for any of the BART-eligible units at the facility. The department sent a notice to the55 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 Decembe r 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 (B ACT) 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 comm ent that changed the units that were subject to the BART air quality screening evaluati on. Mississippi Lime Company has provided a permit modification that includes the continued use of P eerless 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 evalua tion of the facilities’ BART-eligible units. The other unit in the shutdown provision (P RK #3 – EP68) has been dismantled.

Table 9.2: Units Removed from BART Consid eration Due to Shutdown or Federal Permit Requiring Shutdown Facility/Facility ID Units Reason fo r 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 ha s 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 Deterior ation (PSD) review for Permit #0989-003 and a subsequent review for Permit #012005-008. Each re view found that the blast furnace units had

installed Best Available C ontrol Technology (BACT).

The BART-eligible unit at Doe Run – Buick is th e blast furnace (referenced as EP-08, Main Stack). Under the 2005 construction permit, the enti re facility is limited to 3,400 tons per year of

SO 2 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 SO 2 if impact predicted fr om visibility modeling56 exceeded the 0.5 deciview threshold at the near by Mingo National Wildlife Refuge. However, the department did not conduct th is visibility evaluation initia lly due to a 2005 Best Available Control Technology (BACT) review for blast furnace SO 2 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 commente d that this was not sufficient for a BART finding.

Therefore, department staff reviewed the SO 2 BACT finding for the blast furnace and found that three different technologies we re considered: wet scrubbing, dr y scrubbing, and de-sulfurization of feed materials. Dry scrubbing was eliminat ed 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 t echnical option for significant contro l. 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 SO 2 reduced was $3,537, which demonstr ated that this alternative

was cost-ineffective. The continued use of chemi cal de-sulfurization of th e battery paste input to the smelting process at the Buick facility was de termined to be BACT and resulted in the SO 2 emission limit in the 2005 permit. The BART findi ng is equivalent to th e BACT finding in this case due to the high cost of the wet scrubbi ng technology and the on-goi ng benefit of the desulfurization process. In addition to this co st finding and to better understand the visibility impact of the BART-eligible unit, the departme nt conducted a sensitivity analysis of the Doe Run Buick facility on the nearby Mi ngo Class I area. The results of this sensitivity are included below in the refined screening disc ussion 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 visibil ity impairment in a Class I area. The State of57 Missouri has chosen option b. If a state chooses option b, then th e Guidelines suggest three suboptions for determining that certain s ources need not be subject to BART: (1) Individual source attribution approach (dispersion modeling). (2) Use of model plants to exempt s ources with common characteristics. (3) Cumulative modeling to show that no s ources 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 th ese 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 NO X and SO 2 emissions from these sources. The results of this evaluation are included in Table 9.3. Exampl es of CALPUFF/CALPOST mode ling input files used for determining which facilities are subject to BA RT are included in Appendix K. The CALPOST

files included are not universal for all the facili ties modeled. The Noranda facility utilized speciation of the PM emissions to include both a coarse fraction a nd a fine fraction. In addition, the remaining facilities included the PM 10 emissions component as fine particulate matter (PMF) in the CALPOST analyses, but were sometimes called PM 10 or PMF depending on the individual screening analysis.

The State of Missouri utilized two different met hods for evaluation of visibility impacts: (1) Method 2 – modeled relative humidity factors ar e calculated for each hou r/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 wa s determined that Method 2 provides more conservative results for visibility calculati on. Since only Method 6 wa s required by the BART rulemaking, the use of Method 2 gives added conf idence 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: Mi ngo, Hercules Glades, Upper Buffalo, and Mammoth Cave (Kentucky). The screening evaluation criterion wa s a maximum deciview impact of greater than 0.5 deciview to require a refined analysis. Six sources were identified du ring the source-specific screening analyses and these sources were notified to provide re fined CALPUFF modeling58 analyses and/or the department conducted the refined screening anal yses. In acco rdance with the guidelines, a contribution th reshold of 0.5 deciview (98 th percentile) was used for determining which sources were subject to BART us ing the refined modeling approach.

The results of the individual screening analys es 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 200359 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 – Columbia60 The additional analysis on the two CAIR EGU fa cilities (Associated Elec tric – Thomas Hill and Aquila – Lake Road) mentioned above did not illus trate any discernable visibility difference (all

CALPOST values are less than or equal to 0.001). Therefore, resu lts 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 screen ing 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 visib ility impacts over the cont ribute (0.5 deciview) and cause (1.0 deciview) thresholds to decide wh ich Class I area would be necessary for refined analyses. The results shown in Table 9.4 illust rate 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 200261 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 Missour i-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 screen ing evaluation was the use of meteorological observations in the development of the CALMET f iles used in the CALPUFF evaluations. The

emission rates were consistent between the screen ing 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 diffe rent grid parameters for the evaluation. The grid structure is contained in Table 9.5 for bot h analyses. It should be noted that the UMC CALMET analyses were utilized for all the othe r 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 util ized for refined modeling of: BASF Corporation, Independence Power and Light – Blue Valley, Columbia Muni cipal Power Plant, Marshall Municipal, and62 Holcim - Clarksville. Each of these BART-eligib le 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 thes e evaluations of the re levant Class I areas. Please note that based on previous guidance fr om 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 lis t 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 screen ing analyses. The lists of speci fic 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 CA LPUFF/CALPOST issues were addressed to allow for the use of the screening files as a basi s for the development of the refined analysis. Nonetheless, the issues noted are presen ted below for clarification purposes.

9.3.1 University of Missouri-Columbia The review for the BART-eligible unit at UMC (Boiler 10) included th e verification of the CALPUFF concentration results along with a sl ightly 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 PM 10 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.natu re.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 PM 10 emission rate from the boiler a nd converted the concentrations directly to PMF for calculation of the visibility ch ange 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 An alysis Results (Boiler PM Speciation Profile) Facility Class I Area Maximum Method 6

Impact 8 th 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 (PM 10 =PMF) Method 2 Facility Class I Area Maximum Method 2

Impact 8 th 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 (PM 10 =PMF) Method 6 Facility Class I Area Maximum Method 6

Impact 8 th 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 200364 The results clearly demonstrate that Boiler 10 at the University of Missouri – Columbia does not

exceed the 98 th percentile visibility impact threshol d 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 a pparent that the use of the PM 10 speciation profile by the source did not impact the visibility cha nge. This is due to the fact that SO 2 emissions from this boiler contribute over 90 per cent of the visibility impact at all the relevant Class I areas evaluated when the impacts are above 0.5 deciview. Further, the SO 2 emissions calculation from this source was based on a potential maximum emi ssion rate (maximum hourly design rate * emission factor).

9.3.2 Noranda

The Noranda evaluation is one of the BART an alysis conducted by the State of Missouri with emission rates that do not represent the maximum allo wable rates for all polluta nts. 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 SO 2 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 firs t three sources, the methodology for calculating the emissions was as follows: 1) Obtain the maximum combined daily al uminum 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 carr yover of aluminum in certain situations, 2) Obtain the maximum coke sulfur content, 3) Calculate the maximum ratio of tons a node consumed to tons aluminum, and 4) Multiply the maximum daily tapped aluminum (December 24, 2004) by the

maximum ratio of tons anode/tons alum inum (0.413), the maximum coke sulfur content (2.82 percent), and the molecular weight ratio of SO 2 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 SO 2 /day65 Line 2 600,400 tons aluminum/day * 0.413 * 0.0282 * 1.998 = 13,971.3 lb SO 2 /day

These emissions were then distributed to the st ack and roof monitors using a previous permit relationship (95 percent stack vs. 5 percent mon itor) for each line. The final modeled emission

rate for these three sources was:

Monitor – Potline 1 => 10,907.2 lb SO 2 /day * 0.05 = 545.4 lb SO 2 /day Monitor – Potline 2 => 13,971.3 lb SO 2 /day * 0.05 = 698.6 lb SO 2 /day Stack for Potline 1&2 => 24,878.5 lb SO 2 /day * 0.95 = 23,634.5 lb SO 2 /day

It should be noted that the NO X emission rates for these source s also used the same maximum tapping rates for this calculation.

The carbon bake furnace emissions were calculate d using the monthly amount of pitch received along with the maximum sulfur content of the pitc h 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 N ovember 2005 (0.72 percent S). The calculation of

emissions from all three furnaces is as follows:

2,230 tons pitch/month * (0.0072 t on S/ ton pitch) * 1.998 ton SO 2 /ton S =

31.634 ton SO 2 /month

Then, the aluminum production at the three potline/furnace combinations for September 2005 was documented and a production ratio was calculat ed for each set. This ratio was then multiplied for potlines 1 and 2 by the total maximum SO 2 emissions/month. The daily “maximum” was evaluated using the maximum monthly emissions divi ded by 30 days/month.

The calculation of emissions is as follows:

14,068,215 September 2005 production Line 1 13,844,190 Production Line 266 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 SO 2 /month * 0.3275 / 30 day/month =

0.3453 ton SO 2 /day = 690.68 lb SO 2 /day

Line 2 Emissions = 31.634 ton SO 2 /month * 0.3223 / 30 day/month =

0.3399 ton SO 2 /day = 679.71 lb SO 2 /day

All these emissions were utilized in both the screening and the refined meteorological evaluations for Noranda’s impacts a nd can be found in Appendix M.

One issue was identified with respect to the refine d analyses completed by Noranda’s contractor. In CALMET, the location of the su rface, upper air, and precipitation stations is required to allow the model to develop the appropria te 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 pr ocured 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 No randa’s BART-eligible sources do not cause or contribute to a visibility problem at Mingo.

Table 9.9: Noranda Refined Analys is 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 200367 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 98 th percentile visibility impact threshold of 0.5 deciview ev en if the more conser vative CALPOST Method 2 methodology is used.

9.3.3 Independence Power and Light – Blue Valley The emission rates used for the BART-eligible un it (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 fi ve 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: SO 2 – 115.14

lb SO 2 /ton coal, 9.70 lb NO X /ton coal, and 35.88 lb PM 10 /ton coal (pre-control). For PM 10 , the uncontrolled emissions were multiplied by (1-Contr ol Efficiency%/100) to reflect the operation of an electrostatic precipitator. The resultant emissions were:

SO 2 -- 26.73 tons coal/hour * 115.14 lb SO 2 / ton coal * 24 hours/day = 73,684.6 lb SO 2 /day

NO X – 26.73 tons coal/hour * 9.7 lb NO X /ton coal * 24 hours/day = 6,222.7 lb NO X /day

PM 10 – 26.73 tons coal/hour * 35.88 lb PM 10 /ton coal * (1-95.5/100) * 24 hours/day =

1035.80 lb PM 10 /day

As previously mentioned, the refined meteorologi cal dataset for this analysis was originated by the University of Missouri – Columbia. The resu lts of the refined analysis for Mingo, Hercules, and Upper Buffalo are presente d in Table 9.11 including the 8 th highest (98 percentile) values. Also, as with the department’s analysis of the University of Missouri – Columbia’s boiler, the

same PM 10 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 I ndependence Power and Light does not exceed the

98 th percentile visibility impact threshold of 0.5 deciview even if the more conservative

CALPOST Method 2 met hodology is used.

9.3.4 Marshall Munici pal Utilities The emission rates used for the BART-eligible un it (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: SO 2 – 134.90

lb SO 2 /ton coal, 22 lb NO X /ton coal, and 19.92 lb PM 10 /ton coal (pre-control). For PM 10 , the uncontrolled emissions were multiplied by (1-Contr ol Efficiency%/100) to reflect the operation of an electrostatic precipitator. The resultant emissions were:

SO 2 -- 11.03 tons coal/hour * 134.90 lb SO 2 / ton coal * 24 hours/day = 35,709.9 lb SO 2 /day

NO X – 11.03 tons coal/hour * 22 lb NO X /ton coal * 24 hours/day = 5,823.7 lb NO X /day

PM 10 – 11.03 tons coal/hour * 19.92 lb PM 10 /ton coal * (1-87.5/100) * 24 hours/day =

659.07 lb PM 10 /day

As previously mentioned, the refined meteorologi cal dataset for this analysis was originated by the University of Missouri – Columbia. The resu lts of the refined analysis for Mingo, Hercules, and Upper Buffalo are presente d in Table 9.12, including the 8 th highest (98 percentile) values. Also, as with the department’s analysis of the University of Missouri – Columbia’s boiler, the69 same PM 10 direct conversion to PMF calculation methodology was utilized to determine visibility impacts in CALPOST.

Table 9.12: Marshall Municipal Utili ties 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 Mars hall Municipal Utilities does not exceed the 98 th percentile visibility impa ct 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: SO 2 – 47.42

lb SO 2 /ton coal, 14.74 lb NO X /ton coal, and 13.2 lb PM 10 /ton coal (pre-control). For PM 10 , the uncontrolled emissions were multiplied by (1-Contr ol Efficiency%/100) to reflect the operation of a cyclone/baghouse combination. The resultant emissions were:

SO 2 -- 13.94 tons coal/hour * 47.42 lb SO 2 / ton coal * 24 hours/day = 15,868.5 lb SO 2 /day

NO X – 13.94 tons coal/hour * 14.74 lb NO X /ton coal * 24 hours/day = 4,932.5 lb NO X /day

PM 10 – 13.94 tons coal/hour * 13.2 lb PM 10 /ton coal * (1-99.75/ 100) * 24 hours/day =

11.04 lb PM 10 /day70 As previously mentioned, the refined meteorologi cal dataset for this analysis was originated by the University of Missouri – Columbia. The resu lts of the refined analysis for Mingo, Hercules, and Upper Buffalo are presente d in Table 9.13 including the 8 th -highest (98 per centile) values.

The same PM 10 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 Ut ilities 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 Colu mbia Municipal Power Plant does not exceed the

98 th percentile visibility impact threshold of 0.5 deciview even if the more conservative

CALPOST Method 2 met hodology 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 Incine rator – 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 NO X emissions from two components: working loss and breathing loss. The working loss throughput was calcula ted by assessing the maximum amount of acid moved through the tank in the last five year s (2,130,000 gallons in 2005) and dividing by the

number of hours acid was “worked” in the ta nk (5,544 hours – 24 hours, 7 days, 33 weeks). This results in 384.1 gallons/hour. Th e emission factor is 0.16 lb NO X /1000 gallons. The resultant

emission calculation is:71 NO X – 0.3841 1000 gal acid/hour * 0.16 lb NO X /1000 gallon * 24 hours/day =

1.5 lb NO X /day

The breathing loss was calculated using the ta nk capacity multiplied by the appropriate emission

factor.

NO X – 124 1000 gal capacity * 1.94 lb NO X /1000 gallons / 365 days/year =

0.66 lb NO X /day

The emissions from the D Incinerator (TC01) utilized the maximum hourly design rate of material (7.75 tons/hour) and the maximum emissi on factor for the last five years for each pollutant – all were 2005. The em issions calculations are below:

SO 2 -- 7.75 tons/hour * 3.841 lb SO 2 / ton * 24 hours/day = 714.4 lb SO 2 /day

NO X – 7.75 tons/hour * 1.662 lb NO X /ton * 24 hours/day = 309.1 lb NO X /day

PM 10 – 7.75 tons/hour * 1.923 lb PM 10 /ton * 24 hours/day = 357.7 lb PM 10 /day

The emissions from the A Incinerator (PR53) utilized the maximum hourly design rate of material (25 tons/hour) and the maximum emissi on factor for the last five years for each applicable pollutant – both were 2006. The emissions calculations are below:

NO X – 25 tons/hour * 8.90 lb NO X /ton * 24 hours/day = 5,340.0 lb NO X /day

PM 10 – 25 tons/hour * 1.35 lb PM 10 /ton * 24 hours/day = 810.0 lb PM 10 /day

The emissions from the B Incinerator (PR54) utilized the maximum hourly design rate of material (25 tons/hour) and the maximum emissi on factor for the last five years for each applicable pollutant – NO X – 2004 and PM 10 - 2005. The emissions calculations are below:

NO X – 25 tons/hour * 3.99 lb NO X /ton * 24 hours/day = 2,394.0 lb NO X /day

PM 10 – 25 tons/hour * 0.588 lb PM 10 /ton * 24 hours/day = 352.5 lb PM 10 /day72 The emissions from the two natural gas-fired boil ers (UTIL07) utilized the maximum heat input of the two boilers (232.5 MMBTU/hour) along w ith a heat content of 1,050 MMBTU/MMCF for natural gas to arrive at 0.2214 MMCF/hour. Th e emission factor (140 lb NOx / MMCF) was obtained from EPA’s AP-42 guidance document. The emissions calculations are below:

NO X – 0.2214 MMCF/hour * 140 lb NO X /MMCF * 24 hours/day = 743.9 lb NO X /day

As previously mentioned, the refined meteorologi cal dataset for this analysis was originated by the University of Missouri – Columbia. The resu lts of the refined analysis for Mingo, Hercules, and Upper Buffalo are presente d in Table 9.14 including the 8 th -highest (98 per centile) values.

The same PM 10 direct conversion to PMF calculation methodology was utilized to determine visibility impacts in CALPOST as with the other boilers reviewed.

Table 9.14: BASF Corporatio n 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 thre shold of 0.5 deciview even if the more

conservative CALPOST Met hod 2 methodology is used.

9.3.7 Doe Run - Buick The emission rates used in this visibility sensi tivity for the BART-eligible unit (Blast Furnace - Main Stack EP08) at Doe Run Buick were ge nerated using the 2005 construction permit limits for this source. Specifically, the facility-wide SO 2 limit was utilized, while the unit specific

limits for NOx and PM10 were used. Th e emission rates are as follows:

SO 2 -- 18,630.1 lb SO 2 /day73 NO X – 20.6 lb NO X /day

PM 10 – 184.8 lb PM 10 /day

The refined meteorological dataset for this sens itivity was originated by the University of

Missouri – Columbia. The results of the refine d analysis for Mingo are presented in Table 9.15 including the 8 th highest (98 percentile) valu es. Also, as with the department’s analysis of the University of Missouri – Columbia’s boiler, the same PM 10 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 (8 th high) Days > 0.5 (M2) Max M6 Impact 98% M6 Impact (8 th 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 SO 2 control necessary for BART.

9.3.8 Holcim - Clarksville Prior to the March 2008 regional haze state im plementation plan submittal, there were two different modeling analyses conducted for Holcim – Clarksville. The first evaluation utilized

SO 2 and NO X emissions from the calculation documen ted below (tons clinker per hour X lb pollutant / ton clinker). The ot her analysis utilized a maximu m 24-hour actual emission rate for

SO 2 and NO X from 2004-07 based on Holcim’s con tinuous emission monitoring system.

The emission rates used in this analysis for the largest BART-eligibl e units at Holcim – Clarksville (EP14 – Main Stack) were generate d by using the maximum clinker throughput for the kiln (175 tons/hour) and the maximum emission f actors over the last five years. The highest annual emission factor for the last five y ears for each pollutant of interest is: SO 2 – 22.97 lb

SO 2 /ton clinker, 13.89 lb NO X /ton clinker, and 0.22 lb PM 10 /ton clinker. The resultant emissions

were:74 SO 2 -- 175 tons clinker/hour * 22.97 lb SO 2 / ton clinker * 24 hours/day = 96,474.0 lb SO 2 /day

NO X – 175 tons clinker/hour * 13.89 lb NO X /ton clinker * 24 hours/day = 58,338.0 lb NO X /day

PM 10 – 175 tons clinker/hour * 0.22 lb PM 10 /ton coal * 24 hours/day = 924.0 lb PM 10 /day

The remaining emission points (mostly handling of materials) were only PM 10 emissions and were calculated based on maximum hourly design rate and emission fact or for the particular operation. These emission points are further documented in Appendix I.

As previously mentioned, the refined meteorologi cal dataset for this analysis was originated by the University of Missouri – Columbia. The resu lts of the refined analysis for Mingo, Hercules, and Upper Buffalo are presente d in Table 9.16 including the 8 th -highest (98 per centile) values.

The same PM 10 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 – Clar ksville exceed the 0.5 d eciview threshold for

all three Class 1 areas fo r both the Method 2 and the Method 6 CALPOST methodology. Therefore, the department contacte d Holcim to pursue control of SO 2 and NO X for BART. The

PM 10 impact on visibility is less than 1 percen t and does not constitute enough impact to pursue control. Holcim initially responded (prior to the March 2008 submittal) th at they were in the process of retrofitting the kiln under permit #082007-019 that requires them to install a mid-kiln firing system for NO X control. As a point of reference, th e department determined that mid-kiln75 firing was equivalent to a 30 per cent reduction from 1990 cement kiln NO X emissions based on EPA information provided duri ng the development of the NO X SIP call.

After the March 2008 SIP submittal, Holcim pr ovided additional information detailing the

maximum 24-hour SO 2 and NO X emissions using continuous em ission 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 preferre d methodology for determin ation of visibility impacts from BART sources (if available). The department utilized the maximum 24-hour emission rates provided by Holcim with the nece ssary filling of missing hourly data. The PM 10 emission rates used in the new analysis were id entical to the previous screening and refined modeling analyses. The resultant emissi ons obtained from the CEM data were:

SO 2 – 4,900.95 lb SO 2 /hr = 117,622.7 lb SO 2 /day on 12/2/2004

NO X – 3049.39 lb NO X /hr = 73,185.3 lb NO X /day on 11/24/2007

These emissions were modeled using the refine d analysis method described above. The Method 6 results are presented in Table 9.17.

Table 9.17: Holcim - Clarksville Pos t-Submittal Refined Analysis Results Facility Class I Area Max M6 Impact 98% M6 Impact (8 th 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

SO 2 and existing low NO X burners and cement kiln dust insu fflation along with the mid-kiln firing of tires at 12 percent fuel rate for NO X control. The mid-kiln firing of tires was estimated76 by Holcim to provide a 20 per cent reduction from existing NO X emission levels. This submittal is included as part of Appendix N.

Based on the review of the Holcim submitta l, the department requested additional SO 2 control information regarding scrubber pr oblems with opacity and instal lation cost, cost evaluation of “local” fuels (specifically, switching from current petroleum coke at 6 percent sulfur to medium sulfur coal), and detailed inform ation 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 (SO 2 ). The department was specifically interested in a partial control of th e 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 SO 2 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 NO X and a 23 percent

reduction of SO 2 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 (usi ng 12 percent total heat in put substitution) and a switch from petroleum coke as the primary kiln fuel to 3 percent sulfur co al (along with the tirederived fuel for NO X control) would constitute BART for th is 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 reducti on from the maximum 24-hour emission rate when using a thirty-day rolling average.

The SO 2 finding was based primarily on the economic evaluation of severa l different control scenarios for the kiln including both wet and dr y 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 Clarks ville kiln’s ability to compete in the cement production market. The fuel switch provided a significant amount of em ission reductions at a77 cost of approximately $3/ton cement pr oduced. The overall cost per ton SO 2 reduced was calculated as $1,148/ton removed. The NO X finding was based on information provided by Cinar (kiln design contractor for Holcim) regarding NO X emission rates when burning tirederived fuel and the department’s serious c oncern over the use of selective non-catalytic reduction on the world’s largest long wet cement kiln. The increas ed certainty of the mid-kiln firing of tires, along with the use of low-NO X burners and cement kiln dust insufflation, provide a firm basis for the finding of NO X BART at Clarksville. In addi tion, this reduction of emissions was to have very little additional cost for the pl ant due to the planned installation of the mid-kiln firing project. The department findings result in a 20 per cent reduction of NO X and a 27 percent

reduction of SO 2 from the maximum 30-day average em issions using the CEM data. As provided in the presumptive BART finding for uti lities, the emission limits are expressed as 30- day rolling averages of 42,287 pounds NO X /day and 58,787 pounds SO 2 /day . The calculation of these averages will include all hours when the ki ln is not operating and those emissions for both pollutants will be entered as zero pounds. Detailed SO 2 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 Clas s I areas. The result s are provided in Table

9.18.

Table 9.18: Holcim - Clarksville B ART Limit Refined Analysis Results Facility Class I Area Max M6 Impact 98% M6 Impact (8 th 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 98 th percentile visibility impact at the Hercules Glade and Upper Buffalo Wilderness Areas. Further, great improvement78 at the more proximate Mingo National Wildlife Re fuge was also demonstrated. The highest 98 th 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 Au gust 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 in cluded in Appendix R). Subsequent comments provided by both Holcim and EPA Region VII nece ssitated some changes to the draft. In December 2008, Holcim informed the department of its intention to stop production at the Clarksville facility after the 1 st quarter of 2009. A mutual deci sion 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 be en no indication that the kiln will be operated further. The final consent agreement was si gned by the department on April 14, 2009, and is included in Appendix S for inclusion in th e 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 CA IR program under part 96 AAA-EEE and, therefore, the CAIR EGU sources are not required to in stall, operate, and maintain BART for SO 2 or NO X .

In summary, the State of Missouri has identified one BART-eligible source in Missouri that entered into a consent agreement with th e department to limit emissions of SO 2 and NO X . 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, or79 4) units were eliminated based on less than th e 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 R EASONABLE P ROGRESS G OAL R EQUIREMENTS 40 CFR 51.308(d)(1) requires Missouri to establish RPGs for each Class I area within the state (in dv) that provide for reasona ble progress towards achieving na tural 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. Th e state must also provide an assessment of the number of years it would take to attain natural vi sibility conditions if improvement continues at the rate represented by the RPG.

The EPA guidance referenced above describe s 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 progr ess. If a state finds that its initial RPG will not result in visibility improvem ent equal to or better than the uniform rate of progress, then th e 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 id entified 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 enviro nmental 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 goal81 for its mandatory Class I areas.

10.2 M ISSOURI R EASONABLE P ROGRESS G OAL In determining reasonable progress goals, C AA §169A(g)(1) requires states to take into

consideration four factor s, however, flexibility in considera tion of factors may be used. The EPA guidance indicates that ...the factors could be used to select wh ich sources or activities should or should not be regulated, or they could be used to determine the leve l or stringency of control, if any, for selected sources or activities, or some combination of both. The factors may be considered both indi vidually and/or in combination. As noted in section 4.1, given the si gnificant emissions reducti ons that we anticipate to result from BART, the CAIR, and the impl ementation of other CAA programs, these reductions may be all that is ne cessary 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 reas sess the reasonable progress fa ctors for sources subject to BART for which you have already completed a BART analysis.

Missouri’s four-factor analysis for this Regional H aze 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 ac hieve the Reasonable Progress Goals. The BART analysis for Missouri also contribut es 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 demons trate that the 2018 visibility goals for Mingo and Hercules Glades have been largely achiev ed 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 ar e effective for a considerable lifetime of the operating units. A discussion in the CAIR rule highlighted belo w (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 SO 2 and NO X , EPA recognized that the air po llution control retrofits that82 result from a program to achieve highl y cost-effective reductions are quite significant and can not be immediately installed. Such retrofits require a large pool of specialized labor resources, in partic ular, 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 larg e capital requirements to improve the transmission system. Furthermore, allo wing 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 installa tions how to deal with some of the engineering challenges that will exist, esp ecially 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 SO 2 allowances). First, the Agency confirmed that the levels of SO 2 and NO X 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 be lieved initial pollution controls could be fully operational (in today 's final action, the first NO X control phase commences in 2009 instead of in 2010, as expla ined 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 NO X ) cost-effectiveness results, although the first phase levels were determined based on feasibility rather t han cost effectivene ss. The 2015 emissions reductions include the 2010 (and 2009 for NO X ) emissions reductions as a subset of the more stringent re quirements 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 provi ded recommendations on additional controls for non-EGUs, which were co nsidered but not adopted due to the following

reasons:

 Proposed controls are not cost e ffective – over $2,000 per ton of SO 2 or NO X

 Emissions below the threshold limit of 100 tons

 Sources passed the BART screening analysis

 Sources already installed c ontrols required by the NO X SIP Call

10.2.3 Four-factor analysis by MRPO In addition to the EPA and Alpine’s analyses , the MRPO and the Minn esota Pollution Control Agency published a report on the f our-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 Da kota, and South Dakota.). The 4- factor report primarily looked at controls on EGUs; ICI boilers ; reciprocating engines and turbines; and mob ile 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 co st effectiveness of additional SO 2 and NO X emissions reduction using two possible cont rol strategies categorized as EGU1 and EGU2. The EGU1 scenario would cap EGU NO X emissions at 0.10 lb/MMBtu of fossil fuel consumption and SO 2 would be limited to 0.15 lb/MMBtu of fossil fu el consumption at EGUs. The EGU2 caps are more stringent at 0.07 lb/MMBtu and 0.10 lb/M MBtu of fossil fuel consumption for NO X and

SO 2 , respectively. The caps are not enforced at the unit level but repr esent a proposed region wide average emission rate to be met through a trading program.

Missouri has concluded that addi tional controls from ICI boilers is unwarranted. Costs across the nine-state region, in terms of dollars per deciview, exceed two bill ion dollars. Similar reasons apply to other point s ources, such as reciprocating en gines 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 dete rmine the remaining useful life of each unit.

10.2.3.2 Energy and non-air quality envir onmental impacts of compliance The 4-factor report also demonstrates the ener gy and non-air quality envi ronmental impacts of controlling emissions. In the nine-state regi on, carbon dioxide emissions are projected to increase from 3,766,000 tons/year to 5,302,000 tons/y ear 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 a nd EGU2 controls, respec tively. The 4-factor report states that the additional gallons would be treated in exis ting facilities. The cost of treating the additional wastewater and the likelihood of new faci lities increases the costs of compliance. The nine-state region would also incur a projected in crease 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 ai r pollution control programs, including CAIR, BACT, and BART, are sufficien t to meet the 2018 Uniform Rate of Progress for the Mingo and Hercules Glades Class 1 ar eas. Missouri has adopted EPA’s CAIR cap and trade program and will participate fully in the SO 2 , annual NO X , and ozone season NOx trading programs. Missouri’s intent is to allow the mark et forces of the CAIR cap and trade program to drive the installation and operati on of cost efficient controls.

Figures 8.1a and 8.1.b. show the Uniform Rate of Progress (URP) and m odeled 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 improveme nt 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 Reasonabl e Progress for Class I areas in Missouri.

Table 10.1: Uniform Rate of Progre ss 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 statio nary 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 C ONSULTATION In determining a reasonable progress rate for each Class I area disc ussed above, Missouri has

consulted with FLMs and the other states/tribes, which (are) reasonably anticipated to cause or86 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 Res ources, 2007. In addition, the minutes from those meetings are in Appendix U)

10.4 R EPORTING 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 L ONG -T ERM S TRATEGY R EQUIREMENTS 40 CFR 51.308(d)(3) requires Missouri to submit a long-term strategy that addresses regional haze visibility impairment for each mandatory Cla ss 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 st ates/tribes where the Class I ar eas are located. This chapter

describes how Missouri meets the long-term strategy requirements.

11.2 C ONSULTATION Missouri will continue to coordi nate and consult with the cons ultation 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 impa irment 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 corresponden ce. The Central Class I areas consultation will be initiated through the Central Cl ass 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 consul tation processes in respons e to any other states that request our participation.

11.3 S HARE OF E MISSION R EDUCTIONS 40 CFR 51.308(d)(3)(ii) requires Miss ouri 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 analys es developed by CENRAP and a dditional weight of evidence analysis developed as part of consultation pl anning to determine cont ributing states (Appendix E). Nine states, including Mi ssouri, Arkansas, Kentucky, Illinoi s, Indiana, Ohio, Oklahoma,88 Tennessee and Texas, were identified as contribu ting to visibility in Mingo and/or Hercules Glades Class I areas. The modeling demonstrat ion has shown that the emission reductions from these contributing states are sufficient to ach ieve RPGs in Missouri’s Class I areas.

Current visibility is estimated from monitored components of PM 2.5 and coarse mass. Models

are used in a relative sense to estimate how curre nt concentrations respond to emission reduction measures. Data analysis is used to iden tify source categories and regions. Current concentrations of particulate matter components ar e adjusted by the relative modeled response to estimate concentrations at the end the first impl ementation period in 2018. Future visibility is estimated from estimated component concentrations of PM 2.5 and PM 10 at the end of the first implementation period. The difference between presen t 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 pr ojections 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 pr ovides information on these control measures.

11.4 L ONG -T ERM S TRATEGY C OMPONENTS 40 CFR 51.308(d)(3)(v) requires Missouri to consider several factors in de veloping its long-term strategy. The ongoing air polluti on control programs described in section 11.4.1. below were used in the modeling demonstrat ion to show that Missouri Cla ss I Areas meet the 2018 RPG. Additional controls beyond the RP G modeling demonstration that ma y 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 NO X and SO 2 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 th e 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 th e worst 20 percent days89 from 2002 (141 Mm-1) to 2018 (96 Mm-1) is primarily due to reductions in SO 4 (35 Mm-1 improvement) from elevated point sources (Figur es E-7a through E-7d of the TSD). Elevated point sources also contribute over half to the to tal 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 NO X 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, follo wing three years modeling study and cost analysis on SO 2 and NO X controls.

As required by CAIR, Missouri developed draf t 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 Me eting. The rules establish a cap and trade system for NO X and SO 2 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 NO X Trading Program and 10 CSR 10-6.366 Clean Air Interstate Rule SO X Trading Program. The state rules include schedules for compliance, sources a ffected by the rule and emissions limitations.

Table 11.1 summarizes the NO X emissions cap for each unit fo r each calendar year between 2009-2014 and 2015 and beyond. Table 11.2 summarizes the SO 2 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 NO X 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 24491 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 2 192 163 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 SO 2 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 1,11893 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 incl udes any CAIR controls that ar e being undertaken in other impacting states that were identified during the Central Class I area s consultation process.

11.4.1. 2 BART Twenty-six potential BART sources have been identified. Twenty-five have been dropped through the screening and refine d analyses. The remaining source (Holcim – Clarksville) entered into a consent agreement with the Missouri Department of Natural Resources to limit

emissions of SO 2 and NO X . No other sources were found to be subject to BART and, therefore, implementation of an emissions trading program, other emission c ontrols or other alternative measure in place of BART are not necessary. Deta iled analyses can be found in Chapter 9 of the

SIP.

Missouri will include BART controls proposed by the eight other impac ting states in its longterm strategy. Arkansas, Oklahoma and Texas have already had their BART rules proposed. Missouri is working with these states to documen t the emissions reduction and control measures required from their sources. Since not all of th e 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 standard s for passenger cars, light trucks and larger passenger vehicles. The program is designe d to focus on reducing the emissions most responsible for the ozone and PM impact from these vehicles – NO X and non-methane organic gases, consisting primarily of hydr ocarbons and contributing to VOCs. The Tier 2 standards will

reduce new vehicle NO X levels to an average of 0.07 gram s per mile. For new passenger cars and light duty trucks, these standards were pha sed in starting in 2004, and the standards were fully phased in by 2007. For heavy trucks and si milar 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 passe nger cars and light truc ks not certified to the primary Tier 2 standards had to meet an interim average standard of 0.30 g/mi NO X . 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 w ith an average standard of 0.20 g/mi NO X , with those not covered by the phase-in meeting a per-vehicle sta ndard (i.e., an emissions “cap”) of 0.60 g/mi

NO X trucks and 0.09 g/mi for similar vehicles.

Tier 4 EPA's Clean Air Nonroad Diesel Rule (Tier 4) requires stringent pollutio n controls on diesel engines used in industries such as construction, agriculture and mining, a nd it will slash sulfur

content of diesel fuel. This rule is the latest in a series of actions th at are designed to reduce emissions from nearly every type of diesel vehi cle and equipment. This nonroad diesel program combines cleaner engine technol ogies with cleaner fuel – sim ilar to the on-h ighway 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 NO X from mobile sources nationwide.

Sulfur levels will also be reduced in nonroad di esel 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 engine95 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 NO X SIP Call

The NO X SIP call was designed to assist downwind oz one areas in attaining the one-hour and 8- hour ozone NAAQS by providing upwind NO X emission control. This rulemaking was developed through the EPA’s interpretation of the Ozone Transport Assessment Group recommendations and subsequent m odeling and cost analysis of NO X controls to reduce ozone transport. The final NO X SIP call was published in the Federal Register on October 27, 1998.

Missouri’s initial rule in response to the NO X 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 NO X /MMBtu heat input for electric generating units in the eastern one-third of th e 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 NO X /MMBtu of heat input. Cyclone boilers (Sibley and Asbury power pl ants) that burn tire-derived fu els are allowed to meet 0.68 lbs

NO X /MMBtu heat input. The compliance date was May 1, 2004.

On April 21, 2004, the EPA finalized the second phase of NO X SIP call. Phase II of the SIP call excluded the portion known as the “coarse grid” (the western 2/3 of Missouri) from the NO X SIP Call, defined the area of the eastern 1/3 of Missouri to in clude the same counties as established in 10 CSR 10-6.350, with the one exception of not incl uding Phelps County, and revised the cap for

NO X emissions from the previous statewide budget of 114,532 tons of NO X per ozone season to a partial state budget of 61,406 tons of NO X 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-fire d stationary internal combustion engines, 90 percent emissions reductions for diesel and dual fuel stationary internal combustion engines, 60 percent emissions reductions for non-utility bo ilers and turbines, and 30 percent emissions reductions for cement manufacturing plants. Sma ll cogeneration units were excluded from the96 NO X SIP Call. Small cogeneration units are units th at 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 Cont rol Program developed 10 CSR 10-6.360 Control of NO X Emissions from Electric Generating Un its and Non-Electric Generating Boilers , 10 CSR 10-

6. 380 Control of NO X Emissions from Portland Cement Kilns , and 10 CSR 10-6. 390 Control of

NO X Emission from Large Stationary Internal Combustion Engines . This set of three rules constitutes Missouri’s response to EPA’s NO X 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 affect ed by the rule and emissions limitations. Table

11.3 summarizes the NO X allowances for each unit during the ozone season.

Table 11.3: NO X SIP Call Emissions Allocation (tons/ozone season) County Plant Facility Name Unit ID NO X 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 NO X 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 NO X 5997 11.4.2 Additional controls beyond RPG modeling demonstration Ongoing air pollution control programs, as descri bed in Section 11.4.1, are sufficient to meet the 2018 Uniform Rate of Progress for the Mingo an d Hercules Glades Class 1 areas. These ongoing programs such as CAIR, BACT, or BART have been demonstrated to be very costeffective in reducing the visibili ty 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 SO 2 /NO X Reasonably Available Control Technology (R ACT) in the St Louis PM 2.5 plan, Illinois Multi-Pollutant Strategy, regional SO 2 and NO X control strategy proposed by Al pine Geophysics (Alpine) for

CENRAP.

11.4.2.1 SO 2 and NO X RACT in St Louis Missouri is in the process of preparing an implementation plan to address the St. Louis PM 2.5 nonattainment problem. In addition to the deve lopment of an attainme nt demonstration, the

PM 2.5 implementation rule requires states to develop all RACT and Reasonably Achievable Control Measures (RACM). All non-EGU SO 2 and NO X sources were identified in the St. Louis

PM 2.5 nonattainment area that had actual emission s 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 PM 2.5 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 Rule s. This multi-pollutant rule will result in measurable reduction in mercury, SO 2 , and NO X emissions. The rule targets the three largest coal-fired power plant companie s in Illinois: Midwest Genera tion, Ameren and Dynegy. These three companies represent 88 pe rcent of Illinois’ 17,007 Megawa tts of electric generating capacity from coal-fired plants. By implement ation of this rule, the Illinois Environmental Protection Agency estimates the total emissions reduction from all three power companies is98 233,600 tons per year of SO 2 and 61,434 tons per year of NO X . This is a drastic improvement compared to emissions re duction achieved by the CAIR.

11.4.2.3 Regional Controls proposed by Alpine Geophysics (Alpine) In February 2006, Alpine was cont racted by CENRAP to assist in developing control strategies

for CENRAP Class I areas. Based on the availa ble cost information and the Area of Influence (AOI) analyses, Alpine proposed a methodology for constructing co ntrol strategy for both EGUs and non-EGUs. Control technologies for different industrial source categories were identified. Regional “CAIR-like” EGU controls, and sub-regi onal (AOI region) – In dustrial, Commercial,

and Institutional boilers and natu ral 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 impac ts of construction activities 40 CFR 51.308(d)(3)(v)(B) requires Missouri to cons ider measures to mitigate the impacts of construction activities. Under the NAAQS, any nona ttainment area in Missouri is required to

consider construction emissions as part of the general conform ity 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 c onformity 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 a nd replacement will be managed in conformance with existing SIP/TIP requirements pertaini ng 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 (S MP) adopted by Missouri is to identify the responsibilities of the Missour i Department of Natural Res ources, FLMs, and state land managers to coordinate procedures that mitigate the impacts of prescribed fire and wildland fire99 used for resource benefits on public health, safety a nd 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 va rious 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 fo r 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 nuisanc e and public safety hazards (e.g., on roadways and at airports) posed by smoke intrusions into po pulated areas; to preven t deterioration of air quality and NAAQS violations; a nd to address visibility impact s in mandatory federal Class I areas. Some strong indications th at an area needs a SMP are: (1 ) citizens increasingly complain of smoke intrusions; (2) the tre nd of monitored air quality values is increasing (approaching the daily or annual NAAQS for PM 2.5 or PM 10 ) because of significant c ontributions 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 PM 2.5 or PM 10 ; or (4) fires in the area significantly contribute to visibility impairment in mandatory federal Class I

areas. None of these four i ndicators currently shows a problem in Missouri. However, the Missouri SMP should provide additional pr otection 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 em ission 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 NO X 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 re sulting from projected changes to emissions 40 CFR 51.308(d)(3)(v)(G) requires Missouri to addr ess the net effect on visibility resulting from changes projected in point, area and mobile source emissions by 2018.

The emission inventory for Miss ouri projects changes to poi nt, area and mobile source inventories by the end of the first implemen tation period resulting from population growth; industrial, energy and natural resources de velopment; land management; and air pollution control. A summary of these changes is give n 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 ar eas resulting from these emission differences is

discussed in the CENRAP Techni cal Support Document (Appendix F).

11.5 F IVE -Y EAR R EVIEW For the 2013 five-year review pro cess, 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 PERI ODIC PLAN REVISIONS

40 CFR 51.308(f) requires a state/tribe to revi se 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 Regi onal Haze Rule, Missouri commits to revising and submitting this regiona l haze implementation plan by July 31, 2018 and every ten years thereafter.

The Missouri Department of Natural Resources Ai r 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) form at as well as in paper copy.

In addition, 40 CFR 51.308(g) requ ires periodic reports evaluati ng 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 regiona l 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 eval uating progress, all requirements listed in 40 CFR 51.308(g) shall be addressed in the plan revision for reasonabl e progress. These criteria are as follows: 1) Assessment of visibility conditions a nd changes for each federal Class I area in Missouri;

2) Implementation status of control measur es included in plan and a summary of emissions reductions achieved from measures;

3) Analysis of emission reductions by po llutant, identified by source or activity;102 4) Assessment of any significant ch anges in anthropogenic emissions;

5) Assessment of whether current plan is sufficient to meet RPGs; and

6) Review of Missouri’s vi sibility 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 Actions103 

### 13.0 DETERMINATION OF THE ADEQ UACY OF THE EXISTING PLAN

Using the modeling and monitoring as described in this plan, a dete rmination has been made that the plan will continue to meet the goal of s howing progress towards reduc ing visibility. Using the consultation process described in this plan, Missouri’s visibili ty goals have been adequately addressed. In addition, through pa rticipation in other states’ c onsultation 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 necessa ry. Depending on the findings of the five-year progress report, Missouri commits to taking one of th e actions listed in 40 CFR 51.308(h): 1) If Missouri determines that the existi ng plan requires no further substantive

revision in order to achieve established goals, the state will provide the EPA with a negative declaration that fu rther revision of the plan is not needed at this time. 2) If Missouri determines that the existi ng plan may be inadequate to ensure reasonable progress due to emissions from other states that participated in the regional planning process, Missouri will pr ovide notification to the EPA and the other states that participated in region al planning. Missouri will collaborate with the other states through th e regional planning proce ss 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 availabl e 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 carry ing out the scheduled incrementa l administrative and technical actions required in the plan. Any resulting plan revisions could include a revision to goals,104 contingency measures, the monitoring strategy, a nd any other parts of the plan as deemed

necessary.105 

### 14.0 REFERENC E INFORMATION

14.1 L IST OF R EFERENCES

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 Nati onal Parks and Wilderness Areas

. National Academy Press. Washington, DC: 1993.

Pace, Thompson G. Methodology to Estimate th e Transportable Fraction (TF) of Fugitive Dust

Emissions for Regional and Ur ban Scale Air Quality Analyses . 3 August 2005. U.S.

Environmental Protection Agenc y. Accessed 26 October 2007

<http://www.epa.gov/ttn/chief/emch/invent/>.

Trijonis, J.C. “National Acid Preci pitation 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 Am bient Air Quality Standards (NAAQS) and

Regional Haze Regulations . EPA. Research Triangle Park, NC: August 2005.

_______ . Guidance for Estimating Natural Visibili ty Conditions under the Regional Haze

Program . EPA. Research Triangle Park, NC: September 2003.106 14.2 L IST OF A CRONYMS AND A BBREVIATIONS

AIRS Aerometric Information Retrieval System Alpine Alpine Geophysics AOI Area of Influence BACT Best Availabl e Control Technology BART Best Available Retrofit Technology CAA Clean Air Act CAIR Clean Air Interstate Rule CAMx Comprehensive Air quali ty 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 Achievab le 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 NH 3 Ammonia NO x Nitrogen Oxides NO 2 Nitrite NO 3 Nitrate NSPS New Source Performance Standards NSR New Source Review OMC Organic Mass Carbon OMH Organic Mass Hydrogen PM Particulate Matter107 Pechan E. H. Pechan & Associates PMF Fine Particulate Matter POG Policy Oversight Group ppm parts per million PSAT Particulate Matter S ource Apportionment Technology PSD Prevention of Significant Deterioration RACM Reasonably Achievable Control Measures RACT Reasonably Availa ble 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 Re search and Characterization SIC Standard Industrial Code SIP State Implementation Plan SMOKE Sparse Matrix Operator Kernel SMP Smoke Management Program SO 4 Sulfate SO 2 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 Improveme nt State and Tribal Association of the Southeast VOC Volatile Organic Compound WIMO Wichita Mountains Class I Area108 14.3 L IST OF A PPENDICES 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 P ublication 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 SO 2 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