Appendix H 

Reasonable Progress Evaluation 

and Long Term Strategy 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 1 

Regional Haze SIP for Class I Areas April 4, 2008 

TABLE OF CONTENTS 

LIST OF ATTACHMENTS ........................................................................................................... 2

PURPOSE ....................................................................................................................................... 3

1.0 EMISSIONS CONTROLS MODELED ................................................................................... 4

1.1 Point Source Controls ........................................................................................................... 7 

1.1.1 Electric Generating Units ............................................................................................... 7 

1.1.2 Non-EGUs.................................................................................................................... 13 

1.2 Area Source Controls .......................................................................................................... 15 

1.3 Mobile Sources ................................................................................................................... 16 

1.4 Non-Road ............................................................................................................................ 16 

1.5 Conclusion .......................................................................................................................... 17 

2.0 UNIFORM RATE OF PROGRESS ....................................................................................... 19

3.1 Evaluation for Great Smoky Mountains National Park ...................................................... 22 

3.3 Summary ............................................................................................................................. 24 

4.0 REASONABLE PROGRESS EVALUATION ...................................................................... 25

4.1 Area of Influence Analyses ................................................................................................. 25 

4.2 Source Type Analyses ........................................................................................................ 26 

4.3 Back Trajectory Analyses ................................................................................................... 27 

4.4 Area of Influence (AoI) Data and Displays ........................................................................ 30 

4.5 Importance of Pollutants Other Than Sulfate ..................................................................... 37 

4.6 Summary of Emission Inventories Used in Reasonable Further Progress (Cost Curve) 

Analysis .............................................................................................................................. 38 

4.7 Process in Preparing Files for Cost Effectiveness Curve Development ............................. 40 

4.8 Application of AirControlNET Technologies .................................................................... 41 

4.9 Development of AoI-Based Cost Curves ............................................................................ 42 

5.0 REASONABLE PROGRESS ASSESSMENT ...................................................................... 43

6.0 FOUR FACTOR ANALYSIS ................................................................................................ 50

6.1 The Four Statutory Factors ................................................................................................. 50 

6.1-1 Cost of Compliance ..................................................................................................... 50 

6.1-2 Time Necessary for Compliance ................................................................................. 50 

6.1-3 Energy and Non-Air Quality Environmental Impacts of Compliance ........................ 51 

6.1-4 Remaining Useful Life of the Source .......................................................................... 51 

6.2 Evaluating Four Statutory Factors for Specific SO2 Emissions Sources in Each Area of 

Influence (AoI) ................................................................................................................... 51 

6.2-1 Cost of Compliance ..................................................................................................... 52 

6.2-2 Time Necessary for Compliance ................................................................................. 53 

6.2-3 Energy and Non-Air Environmental Impacts .............................................................. 53 

6.2-4 Remaining Useful Life ................................................................................................ 53

6.3 Process of Applying Statutory Factors ............................................................................... 53 

Table 6-3. Tennessee Sources Impacting Class I Areas within 300 km ................................... 57 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 2 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 6-6. INVISTS Extract From EPA Table 1A (EPA-F/452-03-34) .................................. 61 

for Boilers<2,000 MMBtu/hr .................................................................................................... 61 

Table 6-7. INVISTA SUMMARY OF CONTROLS ............................................................... 61 

Table 6-8. INVISTA TIME FOR COMPLIANCE .................................................................. 61 

Table 6-9. INVISTA ENERGY & NON-AIR ENVIRONMENTAL IMPACTS .................... 61 

7.0 Best Available Retrofit Technology ....................................................................................... 64

7.1 Background ......................................................................................................................... 64 

7.2 Summary of BART Determinations ................................................................................... 64 

8.0 FINAL LONG TERM STRATEGY (LTS) AND REASONABLE PROGRESS GOALS 

(RPGs)........................................................................................................................................... 65

8.1 Long-Term Strategy (LTS) ................................................................................................. 65 

8.2 What Additional Emissions Controls Were Considered as Part of the Long-Term Strategy 

for Visibility Improvement by 2018? ................................................................................. 67 

8.3 Reasonable Progress Goals (RPGs) .................................................................................... 68 

REFERENCES: ............................................................................................................................ 70

LIST OF ATTACHMENTS 

Appendix H.1 – VISTAS AOIs for Class I Areas 

Appendix H.2 – VISTAS Control Costs 

Appendix H.3 – Electric Generating Units Controls Applied in Regional Haze Modeling 

Appendix H.4 – EPA Guidance for Setting Reasonable Progress Goals 

Appendix H.5 – Four Factor Analysis Source Reports 

Appendix H.6 - TDEC-APC Rule for Control of Fugitive Dust 

Appendix H.7 – RPG Source Permits 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 3 

Regional Haze SIP for Class I Areas April 4, 2008 

PURPOSE 

The purpose of this appendix is to outline the State’s strategy for complying with the 

requirement to set and meet Reasonable Progress Goals (RPGs) as part of our Regional Haze SIP 

under 40 CFR 51.308(d)(1), and the requirements for establishing best available retrofit 

technology (BART) controls under 40 CFR 51.308(e). 

In the 1977 amendments to the Clean Air Act (CAA), Congress set a national goal for visibility 

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

mandatory Class I Federal areas which impairment results from manmade pollution”. The 

regional haze rule (RHR) at 51.308(d) requires states to demonstrate reasonable progress toward 

meeting the goal of a return to natural visibility conditions by 2064. As a guide for reasonable 

progress, the RHR directs states to graphically show what would be a “uniform rate of progress” 

toward natural conditions for each Class I area. This is known as the “glidepath. The RHR then 

requires states to establish RPGs for visibility improvement at each affected Class I area 

covering each approximately 10-year period until 2064. Therefore, our first set of RPGs will 

comprise our long term strategy (LTS) covering the period from the present until 2018. This 

appendix provides an overview of this first LTS. In addition, a specific component of each 

state’s first LTS is dictated by the specific BART requirements in 40 CFR 51.308(e). This 

appendix will also include a discussion of our strategy for developing those BART requirements. 

Tennessee’s LTS contains the following components: 

I. Inventory of all controls required or expected under all federal and state regulations by 

2009 and 2018. These controls are referred to as “on the books” or “on the way” 

(OTB/OTW). 

II. Modeled expected visibility improvement from OTB/OTW (Base G) controls and 

Comparison of Base G results for 2018 to the uniform rate of progress, or “glidepath” for 

the Great Smokys National Park (GRSM) and Joyce Kilmer –Slickrock (JOKI) National 

Wilderness Area. 

III. Discussion of emissions sensitivity model runs to help determine which pollutants and 

source categories are contributing the most to visibility impairment at Class I areas (runs 

conducted by Georgia Institute of Technology). 

IV. Examination of SO2 Area of Influence (AoIs) projections for GRSM and JOKI, and also 

for any surrounding states’ Class I areas whose AoI includes any Tennessee sources, to 

determine which specific sources are most likely to be impairing visibility. 

V. Application of the four “statutory factors,” listed in 40 CFR 51.308(d)(1)(i)(A) to those 

sources identified in the previous step 

VI. Using the results of the four factor analyses, identification of control determinations for 

specific sources. 

VII. Identification of BART-eligible sources. 

VIII. BART exemption modeling for BART-eligible sources. 

IX. BART determinations for sources subject to BART. 

X. Modeling demonstration of visibility improvement after inclusion of BART and 

reasonable progress control determinations. 

XI. Determination of RPGs based on the visibility improvement expected by 2018. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 4 

Regional Haze SIP for Class I Areas April 4, 2008 

1.0 EMISSIONS CONTROLS MODELED 

2009 and 2018 (Base G) emissions projections include the following existing state and federal 

regulations: 

• Clean Air Interstate Rule (CAIR) + Clean Air Mercury Rule (CAMR). Utility 

projections are based on Integrated Planning Model® (IPM®). CAIR will permanently 

cap emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) in the eastern United 

States. CAIR achieves large reductions of SO2 and/or NOx emissions across 28 eastern 

states and the District of Columbia. When fully implemented, CAIR will reduce SO2 

emissions in these states by over 70 percent and NOx emissions by over 60 percent from 

2003 levels. The Clean Air Mercury Rule will build on EPA’s Clean Air Interstate Rule 

(CAIR) to significantly reduce emissions from coal-fired power plants -- the largest 

remaining sources of mercury emissions in the country. When fully implemented, these 

rules will reduce utility emissions of mercury from 48 tons a year to 15 tons, a reduction 

of nearly 70 percent. 

• NOx SIP Call. Phase I of the NOx SIP call applies to certain Electric Generating Units 

(EGUs) and large non-EGUs, including large industrial boilers and turbines, and cement 

kilns. States in the Visibility Improvement – State and Tribal Association of the 

Southeast (VISTAS) region affected by the NOx SIP call have developed rules for the 

control of NOx emissions that have been approved by EPA. The available State rules and 

guidance documents were reviewed to determine the affected sources and ozone season 

allowances. Information in the EPA’s CAMD NOx Allowance Tracking System – 

Allowances Held Report was also obtained and reviewed. Since these controls are to be 

in effect by the year 2007, we capped the emissions for NOx SIP call affected sources at 

2007 levels and carried forward the capped levels for the 2009/2018 future year 

inventories. This rule resulted in a 68% reduction in NOx emissions from the State’s large 

stationary combustion sources. Phase II of the NOx SIP Call applies to reciprocating 

internal combustion engines with an average daily NOx emission rate of greater than one 

ton (during the baseline period of ozone season 1995). These units were required to 

reduce NOx emissions by not less then 82% of the Projected 2007 Ozone Season Base 

NOx Emissions by the control period of May 1 through September 30, 2007 and must 

maintain that reduction during future control periods. 

 

• NC Clean Smokestacks Act. Under the act, enacted in 2002, coal-fired power plants in 

North Carolina must achieve a 77% cut in nitrogen oxide (NOx) emissions by 2009 and a 

73% cut in sulfur dioxide (SO2) emissions by 2013. 

• Consent Agreements (TECO, VEPCO, Gulf Power Crist 7, Santee Cooper, EKPC and 

APCO Plant Miller). 

• Under a settlement agreement, by 2008, Tampa Electric will install permanent emissionscontrol equipment to meet stringent pollution limits; implement a series of interim 

pollution-reduction measures to reduce emissions while the permanent controls are 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 5 

Regional Haze SIP for Class I Areas April 4, 2008 

designed and installed; and retire pollution emission allowances that Tampa Electric or 

others could use, or sell to others, to emit additional NOx, SO2, and PM. 

• Virginia Electric and Power Co. (VEPCO) agreed to spend $1.2 billion by 2013 to 

eliminate 237,000 tons of SO2 and NOx emissions each year from eight coal-fired 

electricity generating plants in Virginia and West Virginia. 

• A 2002 agreement calls for Gulf Power to upgrade its operation to cut NOx emission rates 

by 61% at its Crist generating plant by 2007, with major reductions beginning in early 

2005. The Crist plant is a significant source of NOx emissions in the Pensacola area. 

• A 2004 consent agreement calls for Santee Cooper to install and commence operation of 

continuous emissions control equipment for PM/SO2/NOx emissions; comply with 

system-wide annual PM/SO2/NOx emissions limits; agree not to buy, sell or trade 

PM/SO2/NOx allowances allocated to Santee Cooper System as a result of said 

agreement; and to comply with emission unit limits of said agreement. 

• A July 2, 2007 consent agreement between the U.S. EPA and East Kentucky Power 

Cooperative (EKPC) requires the utility to reduce its emissions by 62,000 tpy (including 

54,000 tons of SO2 and 8,000 tons of NOx) by installing/operating selective catalytic 

reduction (SCR) technology; low-NOx burners, and PM and Mercury Continuous 

Emissions Monitoring at the utility’s Spurlock, Dale and Cooper Plants. According to 

the EPA, the plant’s total emissions will drop from between 50 – 75% from 2005 levels. 

As with all federal Consent Decrees, EKPC is precluded from using reductions required 

under other programs, such as the Clean Air Interstate Rule (CAIR). EKPC is expected 

to spend over $600 million on pollution controls. 

• Alabama Power Company – Plant Miller (Jefferson County) On April 25, 2006, the U.S. 

EPA and the Department of Justice announced a settlement with Alabama Power 

Company (APC) to reduce emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) 

from Boiler Units 3 and 4 at its Plant Miller in Quinton, Alabama. The plant is required 

to reduce SO2 by installing flue gas desulfurization (FGD) and is required to reduce NOx

by installing selective catalytic reduction (SCR) equipment. The Consent Decree 

requires APC to commence continuous year-round operation of SCR equipment for 

control of NOx emissions by May 1, 2008. APC is also required to begin year-round 

operation of the FGD equipment for control of SO2 emissions by December 31, 2011. 

The installation and operation of these controls are expected to result in the reduction of 

4,953 tons per year of NOx and 22,788 tons per year of SO2. APC is also required to 

install and operate by December 31, 2008, a mercury continuous emission monitoring 

system. APC is precluded from using the emissions reductions required under other 

programs, such as the Clean Air Interstate Rule (CAIR). In addition, the Consent Decree 

requires APC to purchase and permanently retire $4.9 million worth of 2007 SO2

emissions allowances. 

• 1-hr ozone SIPs Atlanta (Federal Register: June 15, 2005 (Volume 70, Number 114)) / 

Birmingham (March 12, 2004 (Volume 69, Number 49))/ Northern Kentucky (Federal 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 6 

Regional Haze SIP for Class I Areas April 4, 2008 

Register: September 16, 2004 (Volume 69, Number 179)). The purpose of a state 

implementation plan (SIP) is to demonstrate attainment or maintenance of the 1-hour 

ozone National Ambient Air Quality Standard (NAAQS). States must determine which 

Clean Air Act requirements are applicable to their area and submit plans to EPA for 

public comment and approval. 

• Heavy Duty Diesel (2007) Engine Standard. A PM emissions standard for new heavyduty engines of 0.01 grams per brake-horsepower-hour (g/bhp-hr), to take full effect for 

diesels in the 2007 model year. Also includes standards for NOx and non-methane 

hydrocarbons (NMHC) of 0.20 g/bhp-hr and 0.14 g/ bhp-hr, respectively. These NOx and 

NMHC standards will be phased in together between 2007 and 2010, for diesel engines.

Sulfur in diesel fuel must be lowered to enable modern pollution-control technology to be 

effective on these trucks and buses. EPA will require a 97 percent reduction in the sulfur 

content of highway diesel fuel from its current level of 500 parts per million (low sulfur 

diesel, or LSD) to 15 parts per million (ultra-low sulfur diesel, or ULSD). 

• Tier 2 Tailpipe. Tier 2 is a fleet averaging program, modeled after the California Low 

Emissions Vehicle Program (LEV II) standards. Manufacturers can produce vehicles with 

emissions ranging from relatively dirty to zero, but the mix of vehicles a manufacturer 

sells each year must have average NOx emissions below a specified value.

• Large Spark Ignition and Recreational Vehicle Rule. Sets emission standards for these 

categories of nonroad engines and vehicles. 

• Nonroad Diesel Rule. Implements a low sulfur fuel requirement that affects both future 

commercial marine vessels (CMV) and locomotive emissions. 

• Industrial Boiler / Process Heater / Reciprocating Internal Combustion Engines (RICE) 

Maximum Achievable Control Technology (MACT) standards. The EPA issued final 

rules to substantially reduce emissions of toxic air pollutants from industrial, commercial 

and institutional boilers, process heaters and stationary RICE. These rules reduce 

emissions of a number of toxic air pollutants, including hydrogen chloride, manganese, 

lead, arsenic and mercury by 2009. This rule also reduces emissions of sulfur dioxide 

and particulate matter in conjunction with the toxic air pollutant reductions. The applied 

MACT control efficiencies were 4 percent for SO2 and 40 percent for PM10 and PM2.5. 

The EPA’s industrial boiler MACT rules were vacated on June 8, 2007. However, the 

EPA is required under the Clean Air Act to issue revised boiler MACT rules. Should the 

EPA not do so in a timely manner, section 112(j) of the Clean Air Act requires individual 

States to issue MACT determinations for these sources. As such, it is more likely than 

not that by 2018 MACT controls will be required for industrial boilers. Therefore, the 

VISTAS States decided to include control assumptions for industrial boilers due to 

MACT. 

• Combustion Turbine MACT standard. The projection inventories do not include the 

NOx co-benefit effects of the MACT regulations for Gas Turbines or stationary RICE, 

which EPA estimates to be small compared to the overall inventory. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 7 

Regional Haze SIP for Class I Areas April 4, 2008 

• Volatile Organic Chemical (VOC) 2-, 4-, 7-, and 10-year MACT Standards. The point 

source MACTs and associated emission reductions were designed from Federal Register 

(FR) notices and discussions with EPA’s Emission Standards Division (ESD) staff. We 

did not apply reductions for MACT standards with an initial compliance date of 2001 or 

earlier, assuming that the effects of these controls are already accounted for in the 2002 

inventories supplied by the States. 

The following are source category specific controls used to project future year emissions 

inventories: 

1.1 Point Source Controls 

Different approaches were used for the EGU and the non-EGU sectors of the point source 

inventory: 

• For the EGUs, the State relied primarily on the Integrated Planning Model® (IPM® - 

version 2.1.9) to project future generation as well as to calculate the impact of future 

emission control programs, to include CAIR and CAMR. The IPM results were adjusted 

based on state and local agency knowledge of planned emission controls at specific 

EGUs. 

• For non-EGUs, we used recently updated growth and control data consistent with the data 

used in EPA’s CAIR analyses, and supplemented these data with available state and local 

agency input and updated fuel use forecast data for the U.S. Department of Energy. 

 

For both sectors, we generated 2009 and 2018 inventories for a combined on-the-books (OTB) 

and on-the-way (OTW) control scenario. The OTB/OTW control scenario accounts for post2002 emission reductions from promulgated and proposed federal, state, local, and site-specific 

control programs as of July 1, 2004. 

1.1.1 Electric Generating Units 

State and local (S/L) agencies specified a number of changes to the IPM results to better reflect 

current information on when and where future controls would occur. These changes to the IPM 

results primarily involved S/L agency addition or subtraction of future emission controls based 

on the best available data from state rules, enforcement agreements, compliance plans, permits, 

and discussions/commitments from individual companies. 

Table 1-1 lists adjustments to IPM control determinations specified by S/L agencies for the Base 

G 2009/2018 EGU modeling inventories. Table 1-2 lists other adjustments to IPM results 

specified by S/L agencies for Base G modeling inventories. Appendix H-3 - EGU Control List is 

a list of all EGUs in the VISTAS region and the post combustion controls modeled for both 2009 

and 2010 by facility name. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 8 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 1-1. Adjustments to IPM Control Determinations Specified by State and Local 

Agencies for the Base G 2009/2018 EGU Modeling Inventories. 

NOx Emission Controls SO2 Emission Controls 

State Plant Name and ID Unit 2009 2018 2009 2018 

IPM State IPM State IPM State IPM State 

AL James H. Miller 

ORISID=6002 

1 & 2 SCR 

during 

ozone 

season 

SCR 

probable 

yr round 

due to 

CAIR 

SCR 

during 

ozone 

season 

SCR 

probable 

yr round 

due to 

CAIR 

None None None None 

 3 & 4 SCR 

during 

ozone 

season 

SCR yr 

round 

from 

Consent 

Decree 

SCR 

during 

ozone 

season 

SCR yr 

round 

from 

Consent 

Decree 

None Scrubber None Scrubber 

 Barry 1, 2, 3 None SNCR SCR SNCR None None None None 

 ORISID=3 4 None SNCR SCR SNCR None None Scrubber None 

 5 None None SCR SCR None None Scrubber None 

 E C Gaston 1 - 4 SCR None SCR None None None Scrubber None 

 ORISID=26 5 SCR SCR SCR SCR Scrubber None Scrubber None 

 Gorgas 6 & 7 None None None None None None None None 

 ORISID=8 8 & 9 None None None None None Scrubber None Scrubber 

 10 SCR SCR SCR SCR None Scrubber Scrubber Scrubber 

 Charles R. Lowman 1 None None None None None Scrubber None Scrubber 

 ORISID=56 2 & 3 SCR SCR SCR SCR Scrubber Scrubber Scrubber Scrubber 

GA Bowen 1BLR SCR SCR SCR SCR IPM had 

retrofit 

scrubbers 

but little 

emission 

reductions 

None Scrubber Scrubber 

 ORISID=703 2BLR SCR SCR SCR SCR None Scrubber Scrubber 

 3BLR SCR SCR SCR SCR Scrubber Scrubber Scrubber 

 4BLR SCR SCR SCR SCR Scrubber Scrubber Scrubber 

 Wansley 1 SCR SCR SCR SCR IPM had 

retrofit 

scrubbers 

but little 

emission 

reductions 

Scrubber Scrubber Scrubber 

 ORISID=6052 2 SCR SCR SCR SCR None Scrubber Scrubber 

 Kraft 1, 2 None None None None None None None None 

 ORISID=733 3 None None SCR None None None None None 

 McIntosh 

ORISID=6124 

1 None None SCR None None None None None 

 Yates 1 None None None None Scrubber Scrubber Scrubber Scrubber 

 ORISID=728 2, 3 None None None None None None None None 

 4 – 7 None None SCR None None None Scrubber None 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 9 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 1-1 (continued) 

NOx Emission Controls SO2 Emission Controls 

State Plant Name and ID Unit 2009 2018 2009 2018 

IPM State IPM State IPM State IPM State 

GA Hammond 1 None None SCR SCR None Scrubber Scrubber Scrubber 

 ORISID=708 2 None None SCR SCR None Scrubber Scrubber Scrubber 

 3 None None SCR SCR None Scrubber Scrubber Scrubber 

 4 SCR SCR SCR SCR Scrubber Scrubber Scrubber Scrubber 

KY Ghent 1 None SCR SCR SCR Scrubber Scrubber Scrubber Scrubber 

 ORISID=1356 2 None None SCR SCR None Scrubber Scrubber Scrubber 

 3, 4 None SCR SCR SCR None Scrubber Scrubber Scrubber 

 Coleman C1 None None SCR SCR None Scrubber Scrubber Scrubber 

 ORISID=1381 C2 None None SCR SCR None Scrubber Scrubber Scrubber 

 C3 None None SCR SCR None Scrubber Scrubber Scrubber 

 HMP&L Station 2 H1 SCR SCR SCR SCR Scrubber Scrubber Scrubber Scrubber 

 H2 None SCR SCR SCR Scrubber Scrubber Scrubber Scrubber 

 E W Brown 1 None None None None None Scrubber None Scrubber 

 ORISID=1355 2 None None SCR SCR None Scrubber Scrubber Scrubber 

 3 None None SCR SCR None Scrubber Scrubber Scrubber 

SC Jeffries 3 SCR None SCR None None None None None 

 ORISID=3319 4 None None None None None None None None 

 Wateree WAT1 SCR SCR SCR SCR None Scrubber None Scrubber 

 ORISID=3297 WAT2 SCR SCR SCR SCR None Scrubber Scrubber Scrubber 

 Canadys CAN1 None None None None None None None None 

 ORISID=3280 CAN2 None None None None None None None None 

 CAN3 None None None None None Scrubber None Scrubber 

 Rainey CT1A None SCR None SCR None None None None 

 ORISID=7834 CT1B None SCR None SCR None None None None 

TN Kingston 1 – 8 SCR SCR SCR SCR None None Scrubber Scrubber 

 ORISID=3407 9 None SCR SCR SCR None None Scrubber Scrubber 

 Johnsonville 1 – 10 SCR None SCR SCR None None None None 

 ORISID=3406 

WV Willow Island 2 SCR None SCR SCR Scrubber None Scrubber Scrubber 

 ORISID=3946 

 Kammer 1 -3 SCR None SCR SCR Scrubber None Scrubber Scrubber 

 ORISID=3947 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 10 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 1-2. Other Adjustments to IPM Results Specified by State and Local Agencies for 

Base G 2009/2018 EGU Modeling Inventories. 

State Plant Name and ID Unit Nature of Update/Correction 

FL Central Power and Lime 

ORISID= 10333 

GEN1 Central Power and Lime (ORIS10333) is a duplicate entry. 

This is point 18 in Florida Crushed Stone (12-053-0530021). 

Removed IPM emissions for Central Power and Lime. 

 Cedar Bay Generating 

ORISID=10672 

GEN1 FLDEP disagrees with IPM projections - no knowledge of 

expansion of this facility and the cogeneration facility 

should not grow faster than the underlying industry. Cedar 

Bay is connected to Stone Container (12-031-0310067). 

Replaced IPM emissions with 2002 emissions for Cedar Bay 

(12-031-0310337) times the growth factors for Stone 

Container. 

 Indiantown Cogeneration 

ORISID=50976 

GEN1 FLDEP disagrees with IPM projections - no knowledge of 

expansion of this facility and the cogeneration facility 

should not grow faster than the underlying industry. 

Indiantown is connected to Louis Dreyfus Citrus (12-085-

0850002). Replaced IPM emissions with 2002 emissions for 

Indiantown (12-085-0850102) times the growth factors for 

Louis Drefus Citrus. 

GA Bowen 

ORISID=703 

1BLR 

2BLR 

3BLR 

4BLR 

IPM indicated retrofit scrubbers on all 4 units in 2009, but 

the IPM emissions showed little reductions from 2002 

levels. Changed emissions to reflect scrubbers on 1BLR and 

2BLR by 2009. 

 Wansley 

ORISID=6052 

1, 2 IPM indicated retrofit scrubbers on both units in 2009, but 

the IPM emissions showed little reductions from 2002 

levels. Changed emissions to reflect one scrubber on Unit 1 

by 2009. 

 Riverside 

ORISID=734 

4 All of plant Riverside was retired from service June 1, 2005; 

emissions set to zero in 2009 and 2018. 

 McIntosh 

ORISID=727 

CT10A 

CT10B 

CT11A 

CT11B 

The McIntosh Combined Cycle facility became commercial 

June 1, 2005. Added 346 tons of NOx and 121 tons of SO2

per unit to the 2009 and 2018 inventories. 

 Longleaf Energy Station 1, 2 Longleaf Energy Station is being proposed by LS Power 

Development, Inc. GA specified that the emissions from this 

proposed plant be included in the 2018 projections. Boilers 1 

and 2 added 1,882 tons of NOx and 3,227 tons of SO2 per 

unit to the 2018 inventory. 

MS R D Morrow 

ORISID=6061 

1, 2 Revised the 2018 emissions to reflect controls not indicated 

by IPM. The SO2 emissions are much lower than IPM, but 

their expected NOx emissions are actually higher than IPM. 

The controls will be coming online 2009 or 2010, so the 

2009 inventory did not change. 

 Jack Watson (2049) 

Victor J Daniel (6073) 

Chevron Oil (2047) 

All MS DEQ specified that the emission projections provided by 

the Southern Company for their units in Mississippi were to 

be used instead of the IPM results. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 11 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 1-2 (continued) 

State Plant Name and ID Unit Nature of Update/Correction 

NC G G Allen (2718) 

Belews Creek (8042)1 

Buck (2720) 

Cliffside (2721) 

Dan River (2723) 

Marshall (2727) 

Riverbend (2732) 

All Replaced all IPM 2009 results with emission projections 

from Duke Energy’s North Carolina Clean Air Compliance 

Plan for 2006. Used IPM results for 2018 

 Asheville (2706) 

Cape Fear (2708) 

Lee (2709) 

Mayo (6250) 

Roxboro (2712) 

Sutton (2713) 

Weatherspoon (2716) 

All Replaced all IPM 2009 results with emission projections 

from Progress Energy’s North Carolina Clean Smokestacks 

Act Calendar Year 2005 Progress Report. Used IPM results 

for 2018 

 Dwayne Collier Battle 

Cogeneration Facility 

ORISID=10384 

GEN1 

GEN2 

Dwayne Collier Battle is a duplicate entry. This is Cogentrix 

of Rocky Mount (37-065-3706500146, stacks G-26 and G27). Duplicate entries were removed both the 2009 and 2018 

inventories. 

 Kannapolis Energy 

Partners 

ORISID=10626 

GEN2 

GEN3 

Kannapolis Energy emissions are being used as credits for 

another facility. IPM emissions from this facility (37-025-

ORIS10626) were removed from the EGU inventory for 

2009 and 2018. Emissions from Kannapolis Energy (37-025-

3702500113) were carried forward in the 2009/2018. 

SC Cross 

ORISID=130 

1, 2 Unit 1: upgrade scrubber from 82 percent to 95 percent 

removal efficiency by June 30, 2006. Recalculate emissions 

based on upgrade in control efficiency. 

Unit 2: upgrade scrubber from 70 percent to 87 percent 

removal efficiency by June 30, 2006. Recalculate emissions 

based on upgrade in control efficiency. 

 Winyah 

ORISID=6249 

1 – 4 Unit 1: Install scrubber that meets 95 percent removal 

efficiency by Dec. 31, 2008; Upgrade ESP from 0.38 to 0.03 

lb/mmBTU by Dec. 31, 2008 

Unit 2: Replace scrubber with one that meets 95 percent 

removal efficiency from 45 percent by Dec. 31, 2008; 

Upgrade ESP from 0.10 to 0.03 lb/mmBTU by Dec. 31, 

2008 

Unit 3: Upgrade scrubber from 70 percent to 90 percent 

removal efficiency by Dec. 31, 2012; Upgrade ESP from 

0.10 to 0.03 lb/mmBTU by Dec. 31, 2012 

Unit 4: Upgrade scrubber from 70 percent to 90 percent 

removal efficiency by Dec. 31, 2007; Upgrade ESP from 

0.10 to 0.03 lb/mmBTU by Dec. 31, 2007 

Recalculated SO2 and PM emissions based on upgrade in 

control efficiencies. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 12 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 1-2 (continued) 

State Plant Name and ID Unit Nature of Update/Correction 

SC Dolphus Grainger 

ORISID=3317 

1, 2 Unit 1: Upgrade ESP from 0.60 to 0.03 lb/mmBTU by Dec. 

31, 2012. Reduced PM10 and PM25 emissions in 2018 by 95 

percent based on change in allowable emission rate 

Unit 2: Install low NOx burners that meet 0.46 lb/mmBTU 

from 0.9 by May 1, 2004. Recalculated NOx emissions using 

0.46/lbs/mmBtu and IPM heat input 

Unit 2: Upgrade ESP from 0.60 to 0.03 lb/mmBTU by Dec. 

31, 2012. Reduced PM10 and PM25 emissions in 2018 by 95 

percent based on change in allowable emission rate 

SC Jeffries 

ORISID=3319 

3, 4 Unit 3: Upgrade ESP from 0.54 to 0.03 lb/mmBTU by Dec. 

31, 2012. Reduced PM10 and PM25 emissions in 2018 by 

94.44 percent based on change in allowable emission rate 

Unit 4: Upgrade ESP from 0.54 to 0.03 lb/mmBTU by Dec. 

31, 2012. Reduced PM10 and PM25 emissions in 2018 by 

94.44 percent based on change in allowable emission rate 

 W S Lee 

ORISID=3264 

1, 2 IPM does not indicate that these units are installing SOFA 

NOx control technology by April 30, 2006 to meet 0.27 

lb/mmBTU, down from 0.45 lb/mmBtu. Calculated NOx

emissions using IPM heat input and 0.27 lbs/mmBtu 

 Generic Unit 

ORISID=900545 

All All predictions for generic units appear reasonable with the 

exception of Plant ID ORIS900545 Point ID GSC45 which 

was modeled in Georgetown County. It will be very difficult 

to add new generation this close to the Cape Romain Class I 

area. Santee Cooper has no plans for future generation in 

Georgetown County, but does have plans for new future 

generation in Florence County. This unit was moved to 

coordinates specified in Florence County. 

VA AEP Clinch River 

ORISID=3775 

1, 2, 3 Replaced all 2009/2018 IPM results using VADEQ’s growth 

and control estimates. 

 AEP Glen Lyn 

ORISID=3776 

51, 52, 

6 

Replaced all 2009/2018 IPM results using VADEQ’s growth 

and control estimates. 

 Dominion Clover 

ORISID=7213 

1, 2 Replaced all 2009/2018 IPM results using VADEQ’s growth 

and control estimates. 

 Dominion Bremo 

ORISID=3796 

3, 4 Replaced all 2009/2018 IPM results using VADEQ’s growth 

and control estimates. 

 Dominion Chesterfield 

ORISID=3797 

3, 4, 

5, 6 

Replaced all 2009/2018 IPM results using VADEQ’s growth 

and control estimates. 

 Dominion Yorktown 

ORISID=3809 

1, 2, 3 Units 1, 2: Replaced all 2009/2018 IPM results using 

VADEQ’s growth and control estimates. 

Unit 3: IPM predicts zero heat input for this 880 MW #6 oil 

fired unit. IPM does not predict a retirement, just that the 

heat input is zero. Dominion plans to continue to operate 

Unit 3. Replaced all 2009/2018 IPM results using VADEQ’s 

growth and control estimates. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 13 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 1-2 (continued) 

State Plant Name and ID Unit Nature of Update/Correction 

VA Dominion Chesapeake 

ORISID=3803 

1 – 4 Replaced all 2009/2018 IPM results using VADEQ’s growth 

and control estimates. 

 Dominion Possum Point 

ORISID=3804 

3 & 4 

5 

6 

Unit 3&4: IPM had 137 tons of NOx for these units in 2009 

and 111 tons in 2018. VA DEQ specified that the permitted 

emission rates should be used, which equates to 3,066 tons 

in 2009 and 2018. 

Unit 5: IPM had zero heat input for this unit. Replaced all 

2009/2018 IPM results using VADEQ’s growth and control 

estimates. 

Unit 6: Replaced all 2009/2018 IPM results using VADEQ’s 

growth and control estimates. 

 Potomac River 

ORISID=3788 

1 - 5 Units 1&2: IPM retired these units. Mirant has no plans at 

this time to retire any units. Replaced all 2009/2018 IPM 

results using VADEQ’s growth and control estimates. 

Units 3, 4, 5: Replaced all 2009/2018 IPM results using 

VADEQ’s growth and control estimates. 

WV Albright 

ORISID=3942 

1, 2 IPM predicted early retirement for these units. AEP 

indicated there are no for early retirement. For 2009, used 

2002 emissions as these units are not likely to retire by 2009. 

For 2018, used IPM prediction of retirement. 

 Rivesville 

ORISID=3945 

7, 8 IPM predicted early retirement for these units. AEP 

indicated there are no for early retirement. For 2009, used 

2002 emissions as these units are not likely to retire by 2009. 

For 2018, used IPM prediction of retirement. 

 Willow Island 

ORISID=3946 

1, 2 Unit 1: IPM predicted early retirement for these units. AEP 

indicated there are no for early retirement. For 2009, used 

2002 emissions as these units are not likely to retire by 2009. 

For 2018, used IPM prediction of retirement. 

Unit 2: IPM predicted SCR and scrubber for 2009. These 

controls will not be in place by 2009. 

 North Branch Power 

Station 

ORISID=7537 

1A, 1B SO2 Permit Rate was corrected from 2.7 to 0.678 lb/MMBtu. 

Used SO2 Permit Rate of 0.678 lb/MMBtu and IPM 

predicted total fuel used to calculate SO2 emissions in 2009 

and 2018 

 Mt. Storm 

ORISID=3954 

1, 2, 3 SO2 Permit Rate was corrected from 2.7 to 0.15 lb/MMBtu. 

Used SO2 Permit Rate of 0.15 lb/MMBtu and IPM predicted 

total fuel used to calculate SO2 emissions in 2009 and 2018 

1.1.2 Non-EGUs 

The general approach for assembling future year data was to use recently updated growth and 

control data consistent with the data used in EPA’s CAIR analyses, supplement these data with 

available stakeholder input, and provide the results for stakeholder review to ensure credibility.
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 14 

Regional Haze SIP for Class I Areas April 4, 2008 

MACTEC (MACTEC, 2006) used the same control programs for both the 2009 and 2018 nonEGU point inventory. Two control scenarios were developed: on-the-books (OTB) controls and 

on-the-way (OTW) controls. The OTB control scenario accounts for post-2002 emission 

reductions from recently promulgated federal, state, local, and site-specific control programs. 

The OTW control scenario accounts for proposed (but not final) control programs that are 

reasonably anticipated to result in post-2002 emission reductions. 

Maximum achievable control technology (MACT) requirements were also applied, as 

documented in the report entitled Control Packet Development and Data Sources, dated July 14, 

2004. The point source MACTs and associated emission reductions were designed from Federal 

Register (FR) notices and discussions with EPA’s Emission Standards Division (ESD) staff. 

Reductions for MACT standards with an initial compliance date of 2001 or earlier were not 

applied, assuming that the effects of these controls are already accounted for in the 2002 

inventories supplied by the States. Emission reductions were applied only for MACT standards 

with an initial compliance date of 2002 or greater. 

The final Phase II NOx SIP call rule was finalized on April 21, 2004. States had until April 21, 

2005, to submit SIPs meeting the Phase II NOx budget requirements. The Phase II rule applies to 

large internal combustion (IC) engines, which are primarily used in pipeline transmission service 

at compressor stations. Affected units were identified using the same methodology as was used 

by EPA in the proposed Phase II rule (i.e., a large IC engine is one that emitted, on average, 

more than 1 ton per day during 2002). The final rule reflects a control level of 82% for natural 

gas-fired IC engines and 90% for diesel or dual fuel categories. Several S/L agencies provided 

more specific information on the anticipated controls at the compressor stations. This 

information was used instead of the default approach used by EPA in the proposed Phase II rule. 

A summary of Non-EGU point source control programs included in 2009/2018 

projection inventories include: 

• Atlanta / Northern Kentucky / Birmingham 1-hr SIPs 

• Industrial Boiler/Process Heater/RICE MACT. The applied MACT control efficiencies 

were 4% for SO2 and 40% for PM10 and PM2.5 to account for the co-benefit from 

installation of acid gas scrubbers and other control equipment to reduce HAPs.

• NOx RACT in 8-hr nonattainment area (NAA) SIPs. 

• NOx SIP Call Phase I- except where States have adopted Phase II already. Phase I of the 

NOx SIP Call applies to certain large non-EGUs, including large industrial boilers and 

turbines, and cement kilns. States in the VISTAS region affected by the NOx SIP call 

have developed rules for the control of NOx emissions that have been approved by EPA. 

State rules and guidance documents were reviewed to determine the affected sources and 

ozone season allowances. 

• Petroleum Refinery Initiative (October 1, 2003 notice; MS & WV). This initiative 

addresses the most significant Clean Air Act compliance concerns affecting the 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 15 

Regional Haze SIP for Class I Areas April 4, 2008 

petroleum refinery industry. Since December 2000, 17 global refinery settlements have 

been reached with refiners representing nearly 77% of domestic refining capacity. Three 

refineries in the VISTAS region are affected by two October 2003 Clean Air Act 

settlements under the EPA Petroleum Refinery Initiative. The refineries are: (1) the 

Chevron refinery in Pascagoula, Mississippi; (2) the Ergon refinery in Vicksburg, 

Mississippi; and (3) the Ergon refinery in Newell, West Virginia. 

• Reasonable Further Progress 3% plans where in place for one hour plans (Metropolitan 

Washington, DC, and Atlanta, Georgia). 

• VOC 2-, 4-, 7-, and 10-year MACT Standards. The point source MACTs and associated 

emission reductions were designed from Federal Register (FR) notices and discussions 

with EPA’s ESD staff. Reductions for MACT standards with an initial compliance date 

of 2001 or earlier, were not applied, assuming that the effects of these controls are 

already accounted for in the 2002 inventories supplied by the States. 

• Combustion Turbine MACT. The projection inventories do not include the NOx cobenefit effects of the MACT regulations for Gas Turbines or stationary Reciprocating 

Internal Combustion Engines (RICE), which EPA estimates to be small compared to the 

overall inventory. 

• NOx SIP Call (Phase II – remaining states & IC engines). 

For more information on the development of point source inventories, see Appendix D. 

1.2 Area Source Controls 

Controls (including control efficiency, rule effectiveness and rule penetration) provided by the 

States or originally developed for use in estimating projected emissions for U.S. EPA’s Heavy 

Duty Diesel (HDD) rulemaking emission projections and used in the CAIR projections were 

used to calculate controlled emissions. 

The controls obtained by MACTEC (MACTEC, 2006) for the HDD rulemaking were controls 

for the years 2007, 2020, and 2030. Since MACTEC was preparing 2009 and 2018 projections, 

control values for intermediate years were prepared using a straight-line interpolation of control 

level between 2007 and 2020. 

The State enforces Stage I controls for gasoline dispensing facilities in 23 counties and Stage II 

for four counties . The State also enforces open burning controls. 

Stage I is the vapor recovery technology on the underground storage tanks and reduces the 

emissions during the tank filling operations at service stations. Stage II controls address 

dispensing of gasoline from the pump to the vehicle. 

The Compliance Validation Section of TDEC-APC is tasked with inspecting Stage I controls. If 

a facility is not found to be properly maintaining the control equipment, then TDEC-APC sends a 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 16 

Regional Haze SIP for Class I Areas April 4, 2008 

notice of violation informing the facility that the controls are required and gives the facility time 

to correct the violation before fines are accessed. From this information the rule effectiveness 

and rule penetration can be estimated. The rule effectiveness is the percentage of facilities 

complying with the rule, where as the rule penetration is the percentage of facilities requiring 

Stage I controls. Control efficiency is the expected percent reduction from this control 

technology. 

Open burning is treated as a means of waste disposal in rural areas. Materials burned generally 

include household trash, agricultural refuse, landscaping refuse, or scrap wood. The open 

burning emissions inventory includes source category code (SCC) 2610030000, residential open 

burning of household waste and SCC 2610000100, open burning of yard trimmings. Since it is 

illegal to burn within the municipal corporate limits, the rural population in each county is used 

to estimate emissions. The municipal corporate limits are established by local jurisdiction. Open 

burning of other types of materials, such as garbage, shingles, rubber products, paper, treated 

wood, plastic, salvage materials, insulation etc. is prohibited at all times across the state. 

For more information on the development of area source inventories, see Appendix D. 

1.3 Mobile Sources 

Local controls included vehicle emissions inspection and maintenance (I/M) programs, Stage II 

vapor recovery programs, anti-tampering programs, etc. By nature, the assumptions used for the 

2002 initial base year inventory vary across the VISTAS region, but our presumption is that 

these data accurately reflected each State’s situation as it existed in 2002. If a State had no plans 

to change program requirements between 2002 and 2018, we proposed to maintain the 2002 

program descriptions without change. However, if a State planned changes, we requested 

information on those plans. In the final implementation of the inventory, Stage II controls were 

exercised in the area source component of the inventory, since the units used to develop Stage II 

refueling estimates are different between MOBILE6 and the NONROAD models. 

For more information on the development of mobile source inventories, see Appendix D. 

1.4 Non-Road 

Using the 2002 base year emissions inventory for aircraft, locomotives, and commercial marine 

vessels (CMV) prepared as described earlier in this document, corresponding emission 

projections for 2009 and 2018 were developed. Detailed inventory data (both before and after 

controls) for these same emission sources for 1996, 2010, 2015, and 2020 were obtained from 

the EPA's CAIR Technical Support Document. Using these data, combined growth and control 

factors for the period 2002-2009 and 2002-2018 were estimated using straight-line interpolation 

between 1996 and 2010 (for 2009) and 2015 and 2020 (for 2018). This is done at the 

State-county-SCC-pollutant level of detail. According to EPA documentation, the CAIR 

baseline emissions include the impacts of the Tier 4 (T4) non-road diesel rulemaking, which 

implements a low sulfur fuel requirement that affects both future CMV and locomotive 

emissions. 

For more information on the development of non-road source inventories, see Appendix D. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 17 

Regional Haze SIP for Class I Areas April 4, 2008 

1.5 Conclusion 

In conclusion of this discussion on source sector controls, Figures 1.1-1.4 depict pollutant totals 

for NH3, PM2.5, NOx, and SO2 for the various sectors by state for 2002, 2009, and 2018 Base 

G2 modeling. 

Figure 1-1. Annual NH3 emissions – Base G2. 

0

20

40

60

80

100

120

140

160

180

200

Alabama

Florida

Georgia

Kentucky

Mississippi

North Carolina

South Carolina

Tennessee

Virginia

West Virginia

Annual NH3 (Thousand Tons)

Miscellaneous

Nonroad

Onroad

Industrial

Other Fuel Combustion

EGU

2002 Typical

2009 OTW

2018 OTW
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 18 

Regional Haze SIP for Class I Areas April 4, 2008 

Figure 1-2. Annual PM2.5 emissions – Base G2. 

Figure 1-3. Annual NOx emissions – Base G2. 

0

20

40

60

80

100

120

140

160

180

200

Alabama

Florida

Georgia

Kentucky

Mississippi

North Carolina

South Carolina

Tennessee

Virginia

West Virginia

Annual PM-2.5 (Thousand Tons)

Miscellaneous

Nonroad

Onroad

Industrial

Other Fuel Combustion

EGU

2002 Typical

2009 

2018 OTW

0

100

200

300

400

500

600

700

800

900

1,000

Alabama

Florida

Georgia

Kentucky

Mississippi

North Carolina

South Carolina

Tennessee

Virginia

West Virginia

Annual NOx (Thousand Tons)

Miscellaneous

Nonroad

Onroad

Industrial

Other Fuel Combustion

EGU 2002 Typical

2009 OTW

2018 OTW
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 19 

Regional Haze SIP for Class I Areas April 4, 2008 

Figure 1-4. Annual SO2 emissions – Base G2. 

2.0 UNIFORM RATE OF PROGRESS 

The linear rate of improvement sufficient to attain natural conditions by 2064 is referred to as the 

“uniform rate of progress” or “glide path”. The baseline represents the starting point from which 

reasonable progress will be measured. There are two baseline values for each Class I area. 

Using 2000 - 2004 Interagency Monitoring of Protected Visual Environments (IMPROVE) 

monitoring data, the deciview values for the 20% best days in each year are averaged together, 

producing a single average deciview value for the best days. Similarly, the deciview values for 

the 20% worst days in each year are averaged together, producing a single average deciview 

value for the worst days. Extinction from individual PM components is calculated from the 

IMPROVE equation (EPA, 2003; Hand and Malm, 2006). 

The EPA has defined target natural conditions in 2064 for each Class I area (EPA, 2003). For 

each VISTAS Class I area, a baseline visibility using 2000-2004 IMPROVE data and uniform 

rate of progress was established, using EPA default assumptions for calculating visibility and 

natural background (i.e., Method 1 predictions). This work was performed by VISTAS. Most 

recently, the scientific community has reviewed the assumptions used to calculate current and 

natural background visibility and has agreed to revised methods (Hand and Malm, 2006, 

Pitchford, 2006). VISTAS intends to present both the original and revised methods to calculate 

visibility and visibility improvement. Figures 2.1 and 2.2 illustrate the predicted visibility 

improvement by 2018 resulting from the inventory that represents implementation of existing 

federal and state regulations, compared to the reasonable progress assessment for Great Smoky 

0

100

200

300

400

500

600

700

Alabama

Florida

Georgia

Kentucky

Mississippi

North Carolina

South Carolina

Tennessee

Virginia

West Virginia

Annual SO2 (Thousand Tons)

Miscellaneous

Nonroad

Onroad

Industrial

Other Fuel Combustion

EGU

2002 Typical

2009 OTW

2018 OTW
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 20 

Regional Haze SIP for Class I Areas April 4, 2008 

Mountains National Park and Joyce Kilmer - Slickrock Wilderness Area. In the figures, the 

purple lines show the uniform rate of progress to natural condition in 2064 for the 20% worst 

days or 20% best days, and the incremental deciview changes resulting from a uniform rate of 

progress between current (2000-2004 baseline) and natural conditions in 2064. The lines show 

the improvement expected from existing and planned emission controls during the period of the 

first long term strategy. As previously stated, the visibility improvement for Joyce Kilmer – 

Slickrock Wilderness Area is represented by the results for the Great Smoky Mountains National 

Park. 

(Method 1 Prediction = default calculation per EPA guidance) 

Figure 2-2. CMAQ 2018 (Base Best&Final) modeling results compared to Uniform Rate of 

Progress at Great Smoky Mountains. 

Uniform Rate of Reasonable Progress Glide Path

Great Smoky Mountains - W20% Data Days

New Improve Equation, 12 km grid

30.28 28.67

25.79

22.59

19.38

16.18

12.97

11.05

26.72

23.50

0

5

10

15

20

25

30

35

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

Year

Haziness Index (Deciviews)

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

Uniform rate of progress = 4.5 dv by 2018
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 21 

Regional Haze SIP for Class I Areas April 4, 2008 

(Method 1 Prediction = default calculation per EPA guidance) 

Figure 2-3. CMAQ 2018 (Base Best&Final) modeling results compared to Uniform Rate of 

Progress at Joyce Kilmer. 

Uniform Rate of Reasonable Progress Glide Path

Joyce Kilmer - Slickrock - W20% Data Days

New Improve Equation, 12 km grid

30.28 28.67

25.79

22.59

19.38

16.18

12.97

11.05

26.72

23.50

0

5

10

15

20

25

30

35

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

Year

Haziness Index (Deciviews)

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

Uniform rate of progress = 4.5 dv by 2018
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 22 

Regional Haze SIP for Class I Areas April 4, 2008 

3.0 GEORGIA TECH SENSITIVITIES 

Georgia Tech performed emission sensitivities to examine the impact of emission reductions on 

regional haze, annual PM2.5, and 8-hour ozone concentrations using CMAQv4.4_SOAmods on 

the VISTAS 12 km modeling domain, using the 2009 OTW (on the way) Base D emissions. 

Once the key pollutants contributing to visibility impairment at each Class I area were identified, 

the sources or source categories responsible for emitting these pollutants or pollutant precursors 

were determined. Emissions sensitivity analyses were conducted using CMAQ with the 2009 

Base D inventory and considering 30% reductions from major pollutants and source categories. 

Emissions sensitivities were initially conducted using 30% reductions to evaluate responses in 

the range where pollutant values are known to be linearly responsive to changes in emissions. 

Organic carbon and sulfate are assumed to be linearly responsive to changes in primary carbon 

and SO2, respectively, but nitrate and ozone chemistry are linear only in a range less than 50%. 

Thirty percent was chosen to be conservative. The sensitivity runs were initially designed to 

consider pollutant contributions in 2009 to PM2.5 in urban areas; results were also considered 

for Class I areas even though the full benefit of controls anticipated by 2018 are not included in 

these sensitivity analyses. While the 2009 sensitivity analyses cannot be used to judge absolute 

contributions from each state or source sector, the results do indicate relative level of response 

among pollutants, sectors, and geographic areas. 

3.1 Evaluation for Great Smoky Mountains National Park 

Figure 3-1 shows the results of an emissions sensitivity run for GRSM for summer (since 

summer is when 20% worst days occur). CMAQ was run using 30% reductions from the 2009 

Base D inventory assumptions for implementing existing state and federal regulations (Section 

1.0) for major source categories of SO2, NOx, VOC, and PM. The results identify geographic 

origins for visibility impairing pollutants, and serve as a good starting point when considering 

potential air quality benefits from additional controls for specific source sectors in VISTAS 

states or neighboring Regional Planning Organizations (RPOs). The greatest benefits at GRSM 

in 2009 are projected to come from further reducing SO2 emissions from electric generating 

utilities (EGUs). Additional, smaller benefits are projected from additional SO2 emission 

reductions from non-utility, industrial point sources. Reductions of nitrogen oxide emissions 

from point sources (EGU and non-EGU) or ground level sources (on road vehicles, off road 

engines, and area sources) and reductions of primary carbon from point or ground level sources 

are projected to be significantly less beneficial than reductions in SO2 emissions. Reductions in 

anthropogenic VOC emissions show no response in visibility, while a 30% reduction in biogenic 

VOC emissions result in a measurable improvement. However, controlling the VOCs from 

vegetation is not possible or appropriate. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 23 

Regional Haze SIP for Class I Areas April 4, 2008 

Great_Smoky_Mountains, TN 

(Summer)

-12.00

-10.00

-8.00

-6.00

-4.00

-2.00

0.00

2.00

SO2_EGU

SO2_nonEGU

NOx_Ground

NOx_Point

NH3

VOCs

PC_Ground

PC_Point

PC_Fires

∆

Bext (Mm-1)

Bio.

Antro.

BCs

MRPO

M-VU

CEN

VISTAS

WV

VA

TN

SC

NC

MS

KY

GA

FL

AL

Figure 3-1. Summertime sensitivity results for 2009 Base D emissions – Great Smoky 

Mountains. 

Several states contribute to modeled reductions in SO4 at GRSM on the 20% worst days 

modeled in these two episodes in response to further reductions in 2009 SO2 emissions from 

EGUs (Figure 3-2). For this sensitivity run, further reducing SO2 emissions from electricity 

generating utilities in Georgia, Alabama, and South Carolina would have the greatest benefit for 

GRSM; reductions from electric generating utilities in other VISTAS states would have 

additional but smaller benefits at GRSM. Approximately one third of the benefit at GRSM from 

further SO2 emission reductions would come from outside VISTAS states. 

 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 24 

Regional Haze SIP for Class I Areas April 4, 2008 

AL

FL

GA

KY

MS

NC

SC

TN

VA

WV

CEN

M-VU

MRPO

BCs

Utility Contributions, by State and Region, to SO4 at Great Smoky Mtn.,

Using 2009 Emissions and CMAQ model run for 20% Worst Days 2002 

GA = 18%

KY = 5%

FL = 1%

MS = 0.5%

Northeast = 2%

VA = 4%

Central = 1%

NC = 5%

WV = 4%

SC = 12%

TN = 7%

Eastern US = 14%

(Boundary 12-km domain)

Midwest = 12%

AL = 12%

 

Figure 3-2. Utility Contributions, by State and Region to SO4 at GRSM for 20 percent 

worst days using 2009 emissions. 

Similar sensitivity analyses were performed for wintertime using the 2009 inventory. These 

results suggest that in wintertime, reductions in ammonia emissions could be more beneficial for 

reducing ammonium nitrate contributions to visibility impairment than further reducing nitrogen 

oxide emissions from either ground or point sources. Reducing ammonia emissions could also 

be more effective in improving visibility in wintertime than further reductions in SO2 emissions. 

The largest sources of ammonia emissions in this region are agricultural. 

3.3 Summary 

Emissions sensitivity analyses show the relative benefits of reducing different pollutants from 

different source categories and geographic areas. These 2009 sensitivity analyses indicate that 

further reductions in SO2 emissions from EGUs would be most beneficial for visibility at 

VISTAS Class I areas, followed by SO2 reductions from industrial point sources. Controlling 

NOx or primary carbon emissions from either point or ground level sources would have little 

benefit to visibility. Controlling anthropogenic sources of VOC would not be effective in 

improving visibility in winter. In wintertime, controlling ammonia emissions would be more 

effective in reducing ammonium nitrate than controlling nitrogen oxide emissions. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 25 

Regional Haze SIP for Class I Areas April 4, 2008 

4.0 REASONABLE PROGRESS EVALUATION 

4.1 Area of Influence Analyses

The objective of the VISTAS Area of Influence (AoI) analyses is to identify the geographic 

source regions that are contributing to visibility impairment at the Class I areas on the 20% worst 

visibility days. This information will be used by the State as part of the evaluation and 

demonstration of reasonable progress toward visibility improvement in Class I areas. 

VISTAS’ contribution assessment based on IMPROVE monitoring data (Brewer and Adlhoch, 

2005) demonstrated that ammonium sulfate is the major contributor to PM2.5 mass and visibility 

impairment at Class I areas in the VISTAS and neighboring states. As illustrated in Figure 4-1, 

on the 20% worst visibility days in 2000-2004, ammonium sulfate accounted for greater than 

70% of the calculated light extinction at Class I areas in the Southern Appalachians and greater 

than 60% of the calculated light extinction for coastal sites in the VISTAS states (excepting 

Everglades). In contrast, ammonium nitrate contributed less than 5% of the calculated light 

extinction at VISTAS Class I areas on the 20% worst visibility days. (Nitrate has a somewhat 

larger contribution on 20% worst days at Class I areas in neighboring states to the VISTAS 

region.) Particulate organic matter (organic carbon) accounted for 10-20% of light extinction on 

20% worst visibility days (except Everglades where organic carbon accounted for 40%). 

Figure 4-1. Average Extinction for 20% Worst Visibility Days in 2000-2004 using New 

IMPROVE Equation (data from VIEWS Sep 2006). 

0

50

100

150

200

250

300

SWAN1

ROMA1

OKEF1

EVER1

CHAS1

SAMA1DOSO1

SHEN1

JARI1

LIGO1

SHRO1

GRSM1

COHU1

SIPS1

MACA1

CADI1

BRIG1

BRET1

MING1

HEGL1UPBU1

CACR1

VISTAS coastal VISTAS inland non-VISTAS

Extinction (Mm -1)

Sea Salt

CM

Soil

EC

POM

Amm NO3

Amm SO4

Rayleigh

0

50

100

150

200

250

300

SWAN1

ROMA1

OKEF1

EVER1

CHAS1

SAMA1DOSO1

SHEN1

JARI1

LIGO1

SHRO1

GRSM1

COHU1

SIPS1

MACA1

CADI1

BRIG1

BRET1

MING1

HEGL1UPBU1

CACR1

VISTAS coastal VISTAS inland non-VISTAS

Extinction (Mm -1)

Sea Salt

CM

Soil

EC

POM

Amm NO3

Amm SO4

Rayleigh
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 26 

Regional Haze SIP for Class I Areas April 4, 2008 

VISTAS emissions sensitivity analyses using the CMAQ regional air quality model project that 

reductions in SO2 emissions from Electric Generating Utilities (EGU) and non-EGU industrial 

point sources will result in the greatest improvements in visibility at VISTAS Class I areas. EGU 

and non-EGU industrial point sources comprise 95+% of the SO2 emissions inventory in the 

VISTAS states. The emissions sensitivity analyses also indicate that improvements in visibility 

from reductions in NOx or primary carbon emissions from ground- level sources or point sources 

would be small. Based on these analyses, VISTAS states chose to focus their reasonable 

progress evaluation for the first regional haze SIP on potential controls of SO2 emissions from 

EGU and non-EGU point sources. To select the specific point sources that would be considered 

for each Class I area, states first identified the geographic areas that most likely influence 

visibility in each Class I area and then identified the major SO2 point sources in that geographic 

area. 

4.2 Source Type Analyses 

The following analyses are illustrative of an initial approach from September 2005 to evaluate 

potential control strategies. These analyses rely on the 200 km area surrounding the Class I area 

and the Base F4 model run. 

VISTAS emissions inventory for the simplest AoI, the 200 km concentric circle, indicated for 

GRSM in 2018 that fuel combustion from electric utilities and industrial processes produces the 

majority of the remaining SO2 emissions (Table 4-1), with 90% of 2018 SO2 total coming from 

fuel combustion. 

Table 4-1. Source types 2018 Base G2 modeling GRSM – Percentage. 

Annual 2018 Emissions (%) 

Tier VOC NOX CO SO2 PM-10 PM-2.5 NH3 

Fuel Comb. Elec. Util. 0% 22% 1% 54% 11% 21% 1% 

Fuel Comb. Industrial 1% 18% 2% 30% 3% 5% 0% 

Fuel Comb. Other 5% 6% 3% 6% 5% 12% 1% 

Chemical & Allied Product Mfg 2% 0% 0% 2% 1% 1% 0% 

Metals Processing 1% 1% 2% 3% 2% 5% 0% 

Petroleum & Related Industries 0% 0% 0% 1% 0% 0% 0% 

Other Industrial Processes 6% 5% 1% 3% 8% 11% 0% 

Solvent Utilization 44% 1% 0% 0% 0% 1% 0% 

Storage & Transport 6% 0% 0% 0% 0% 1% 0% 

Waste Disposal & Recycling 4% 2% 3% 0% 5% 11% 0% 

Highway Vehicles 18% 25% 48% 0% 2% 2% 11% 

Off-highway 11% 18% 35% 1% 2% 4% 0% 

Miscellaneous 1% 1% 5% 0% 59% 26% 86% 

VISTAS Total 100% 100% 100% 100% 100% 100% 100% 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 27 

Regional Haze SIP for Class I Areas April 4, 2008 

4.3 Back Trajectory Analyses 

TDEC-APC defined AoIs to identify source regions for which additional controls might be 

considered and that are likely to have the greatest impact on each Class I area. Initial focus on 

AoIs is on SO2 emissions because SO4 contributes greater than 60% of the calculated light 

extinction on the haziest days. In fact, in the previous section, figure 4-1 shows that for the 

mountain areas (GRSM), SO4 contributes roughly 80% to the calculated light extinction on the 

haziest days. To better understand the sources that should be considered in a four factor analysis 

for reasonable progress, VISTAS contracted ENVIRON to partner with VISTAS’s Data Analysis 

contractor, Air Resource Specialists (ARS), to provide SO2 AoIs for each VISTAS and six 

neighboring Class I areas. ARS generated meteorological back trajectories for IMPROVE sites 

in VISTAS and neighboring states. Back trajectory analyses use interpolated measured or 

modeled meteorological fields to estimate the most likely central path of air masses that arrive at 

a receptor at a given time. The method essentially follows a parcel of air backward in hourly 

steps for a specified length of time. Back trajectories account for the impact of wind direction 

and wind speed on delivery of emissions to the receptor, but do not account for chemical 

transformation and dispersion of emissions. 

Trajectories were generated using the Hybrid-Single Particle Lagrangian Integrated Trajectory 

(HYSPLIT) model developed by the National Oceanic and Atmospheric Administration’s 

(NOAA) Air Resources Laboratory (ARL). HYSPLIT uses archived 3-dimensional 

meteorological fields generated from observations and short-term forecasts. HYSPLIT can be 

run to generate forward or backward trajectories using several available meteorological data 

archives. 

The data archives used in this analysis were the National Weather Service's National Centers for 

Environmental Prediction Eta Data Assimilation System (EDAS). The EDAS fields are archived 

by the ARL across the continental U.S., including a buffer zone, at a horizontal resolution of 80 

km before 2004, and at a horizontal resolution of 40 km starting in 2004. Detailed information 

regarding the trajectory model and these data sets can be found on NOAA’s Web site 

(http://www.arl.noaa.gov/ready/hysplit4.html). 

The major model parameters selected for this analysis include those listed in Table 4-2. 

Table 4-2. Back Trajectory Model Parameters Selected for VISTAS AoI Analysis 

Model Parameter Value 

Trajectory duration 72 hours backward in time 

Top of model domain 14,000 meters 

Vertical motion option used model data 

Meteorological Field EDAS 

End Times 0600, 1200, 1800 and 2400 EST 

End Heights 100 and 500 m 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 28 

Regional Haze SIP for Class I Areas April 4, 2008 

The choice of these parameters affects the trajectories generated and the final attribution 

analyses. In particular, trajectories tend to become increasingly uncertain the further back in 

time they are used. Vertical motion in the model is sometimes best represented by following 

actual vertical motion measurements (represented by model data), surfaces of constant entropy, 

or surfaces of constant pressure, depending on the meteorological conditions at a given location 

and time. The impact of receptor height (or end height) on an individual trajectory is also 

important. Low-ending trajectories represent air parcels nearer to ground level and high-ending 

trajectories may represent more accurate boundary layer flow above the local terrain. 

For the years 2000 – 2004, back trajectories were computed for the following IMPROVE 

sampling sites in and around the VISTAS region: 

1. Breton, LA (BRET1) 

2. Brigantine NWR, NJ (BRIG1) 

3. Cadiz, KY (CADI1) 

4. Caney Creek, AR (CACR1) 

5. Cape Romain NWR, SC (ROMA1) 

6. Chassahowitzka NWR, FL (CHAS1) 

7. Cohutta, GA (COHU1) 

8. Dolly Sods Wilderness, WV (DOSO1) 

9. Everglades NP, FL (EVER1) 

10. Great Smoky Mountains NP, TN (GRSM1) 

11. Hercules-Glades, MO (HEGL1) 

12. James River Face Wilderness, VA (JARI1) 

13. Linville Gorge, North Carolina (LIGO1) 

14. Mammoth Cave NP, KY (MACA1) 

15. Mingo, MO (MING1) 

16. Okefenokee NWR, GA (OKEF1) 

17. Shenandoah NP, VA (SHEN1) 

18. Shining Rock Wilderness, NC (SHRO1) 

19. Sipsy Wilderness, AL (SIPS1) 

20. St. Marks, FL (SAMA1) 

21. Swanquarter, NC (SWAN1) 

22. Upper Buffalo Wilderness, AR (UPBU1) 

Figure 4-2 shows the 72-hour back trajectory analysis performed for the Great Smoky Mtns. 

National Park. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 29 

Regional Haze SIP for Class I Areas April 4, 2008 

Back Trajectories for 2002 20% Worst Days

Great Smoky Mtns. National Park

 

Figure 4-2. Example 72-hour back trajectories for 20% worst visibility days in 2002 for 

Great Smoky Mtns. National Park. 

Based on the five years of individual back trajectories, ARS generated extinction-weighted 

residence time data for each IMPROVE site. Each hourly trajectory point was tagged with its 

associated sample (or end) date. Back trajectories with end dates corresponding to the 20% 

worst visibility days were weighted with calculated extinction values and summed into 1-degree 

horizontal grid cells of latitude and longitude. 

Extinction data is based on the IMPROVE Regional Haze Rule dataset, as available from the 

VIEWS website (http://vista.cira.colostate.edu/views/Web/IMPROVE/SummaryData.aspx) in 

November 2005 and is calculated based on the original IMPROVE algorithm. For sites with less 

than three complete years of data, ARS developed and applied a data substitution protocol to fill 

missing data. Organic carbon and elemental carbon values were filled based on correlations to 

hydrogen and sulfate values for the same site. Other components were filled based on data from 

nearby sites. 

Trajectory data were weighted by total extinction, and by extinction components including 

ammonium sulfate (AmmSO4), ammonium nitrate (AmmNO3), particulate organic material 

(POM), Light Absorbing Carbon (LAC), Soil, and Coarse Mass (CM). Weighing trajectories for 

the 20% worst days by sulfate extinction gave greater importance to days influenced by SO2 

emissions and lesser importance to days influenced by organic carbon emissions. This allowed a 

geographic AoI to be identified based on sulfate contributions and not skewed by contributions 

from fire. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 30 

Regional Haze SIP for Class I Areas April 4, 2008 

These data files were provided to ENVIRON. ENVIRON was charged with developing 

residence time plots to define the geographic area with highest probability of influencing the 

receptor on the 20% worst days dominated by sulfate. Residence time over an area is indicative 

of general flow patterns, but since it does not account for emissions and removal processes, it 

does not necessarily imply specific areas contributed significantly to haze compounds at a 

receptor site. 

4.4 Area of Influence (AoI) Data and Displays 

The primary objective of the AoI displays and data sets are to assist the State in focusing its 

reasonable progress analysis on those geographic regions and source categories which most 

impact a particular Class I Area. The sources of data used in these analyses include backtrajectory residence time data, provided by ARS and described above, and the VISTAS 2002 and 

2018 36-km gridded emissions data (Base G, August 2006 inventory version). 

Extinction weighted back-trajectory residence time plots were provided by ARS for all Class I 

Areas in the VISTAS region as well as for the surrounding neighboring states. These trajectories 

were processed on an un-projected (i.e., geodetic lat/lon 1 degree by 1 degree) grid and 

transferred to ENVIRON for further GIS processing and analysis. Back-trajectories were run for 

100-meter and 500-meter start heights. Because the back-trajectories were to be combined with 

gridded emissions data, the first step in the analysis and GIS processing involved re-projecting 

these data to the Inter-RPO Unified Lambert Conformal Projection domain. Once the data were 

re-projected, the data were mapped to the 36-km grid cells in the RPO projection using an areaweighted mapping routine. The re-projected extinction weighted back-trajectory residence times 

were then plotted on the VISTAS 12-km modeling domain. As sulfate is the primary visibility 

impairing component of the total extinction in the Southeast, the SO4-weighted residence time 

trajectories were chosen as the basic data set for display. For clarity, these data are scaled by the 

maximum value of the total extinction-weighted residence time within the modeling domain. 

The 100-km and 200-km distances from the Class I area were labeled. 

Using the trajectories with the 100-m start height, the State has defined the SO2 AoI as the area 

with grid cells showing 10% (area shaded in yellow in following plots) or greater residence time 

(the frequency that winds pass over that area on the way to the Class I area on the 20% worst 

days dominated by sulfate) for the period 2000-2004. Residence time over an area is indicative 

of general flow patterns, but since it does not account for emissions and removal processes, it 

does not necessarily imply specific areas contributed significantly to haze compounds at a 

receptor site. Figures 4-3 and 4-4 show the extinction weighted residence time plots for GRSM 

and COHU respectively for 100-m and 500-m trajectory start heights. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 31 

Regional Haze SIP for Class I Areas April 4, 2008 

Define SO2 Area of Influence as area > 10% Residence Time

(area in yellow) using trajectories with 100-m Start Height (left plot)

Green circles indicate 100-km and 200-km radii from Class I area.

Red line perimeter indicate Area of Influence with Residence Time > 10%.

Orange line perimeter indicate Area of Influence with Residence Time > 5%.

Max Bext Value = 724558

Max Value = 84%

Figure 4-3. Great Smoky Mountains SO4 extinction-weighted residence time plots for the 

period 2000-2004. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 32 

Regional Haze SIP for Class I Areas April 4, 2008 

SO2 Area of Influence for Cohutta, GA

Green circles indicate 100-km and 200-km radii from Class I area.

Red line perimeter indicate Area of Influence with Residence Time > 10% (weighted by

sulfate extinction and normalized by total extinction).

Orange line perimeter indicate Area of Influence with Residence Time > 5%.

Figure 4-4. Cohutta SO4 extinction-weighted residence time plots for the period 2000-

2004. 

As an aid to the analysis, all regions with scaled residence time values greater than 5% and 

greater than 10% were noted on the display. Finally, county boundaries were overlaid to identify 

those counties and 36-km modeling grid cells for which the extinction-weighted residence time 

back-trajectories exceeded 5% and 10%. These data were then exported as comma-delimited 

ASCII data files for further analyses. These residence time displays are used primarily to 

determine the regions (counties and/or grid cells) impacting each Class I Area. The next step in 

the analysis is to determine the potential impact from emission sources within the regions 

identified from the extinction-weighted back-trajectory residence time displays and analyses. 

Previous VISTAS contribution assessment, emissions sensitivity modeling, and inventory 

analyses have indicated that SO4 is the largest contributor to haze on the 20% worst visibility 

days and that EGUs and industrial point sources are the largest contributors to SO4 levels at the 

Class I areas. These two source categories make up 95% of the VISTAS SO2 inventory. 

Therefore these two source categories were identified as the highest priority for evaluation of 

reasonable progress in 2018 at the Class I areas. 

The potential impacts of SO2 point source emissions for each Class I Area are determined by 

combining gridded emissions data and weighted back-trajectory residence times for the 36-km 

grid cells. The analysis was carried out with both the 2002 and 2018 base year emission 

inventories. Figures 4-5 and 4-6 display the gridded point source SO2 emissions from the 

VISTAS modeling databases, for 2002 and 2018, respectively. These data were processed by 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 33 

Regional Haze SIP for Class I Areas April 4, 2008 

summing all vertical layers for each grid column and then summing across all days to obtain 

annual emission totals for each grid cell. 

Figure 4-5. Annual 2002 (Base G) point source SO2 emissions for the VISTAS region for in tons/year. 

Figure 4-6. Annual 2018 (Base G) point source SO2 emissions for the VISTAS region for in tons/year. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 34 

Regional Haze SIP for Class I Areas April 4, 2008 

As a way of incorporating the effects of transport, deposition, and chemical transformation of 

point source emissions along the path of the trajectories, these data were weighted by 1/d, where 

d was calculated as the distance between grid cell centers, in kilometers. For the grid cell 

containing the Class I Area monitor, a weighting of 1/9 was applied. The distance-weighted 

point source SO2 emissions are then combined with the gridded extinction-weighted backtrajectory residence times at a spatial resolution of 36-km. 

The final step in the development of the displays and datasets involve the combination of the 

residence times and gridded emission data. The distance weighted (1/d) gridded point source 

SO2 emissions are multiplied by the total extinction-weighted back-trajectory residence times 

(SO2 * Bext-weighted RT * (1/d)) on a grid cell by grid cell basis. These results are then 

normalized by the domain-wide total and displayed as a percentage. The analysis is carried out 

for both the 2002 and 2018 base year inventories. Figures 4-7 and 4-8 display the result of this 

final analysis step. Note that the outlined regions (in red and light orange) represent the extent of 

the >10% and >5% sulfate extinction-weighted residence times, determined from the first step in 

the analysis (see Figures 4-3 and 4-4). As with the residence time analysis, the results of the 

combined distance-weighted SO2 emissions and extinction-weighted residence times are 

overlayed with county boundaries and exported to comma-delimited ASCII data files for further 

analyses of emissions and control options for specific sources. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 35 

Regional Haze SIP for Class I Areas April 4, 2008 

Sources identified outside the SO2 Area of Influence have large emissions even if trajectories 

over those sources are infrequent.

2002 SO2 Emissions weighted by Residence Time 

Green circles indicate 100-km and 200-km radii from Class I area.

Red line perimeter indicate Area of Influence with Residence Time > 10%.

Orange line perimeter indicate Area of Influence with Residence Time > 5%.

2002 SO2 emissions 2002 SO2 emissions

Max Value = 46%

Figure 4-7. Great Smoky Mountains 2002 SO2 Emissions * SO4 extinction-weighted 

residence time plots. 

The following sets of plots show the 2018 SO2 Emissions multiplied by the SO4 extinctionweighted residence time plots. These were produced the same way as the previous plots, only 

using 2018 emissions instead of 2002 emissions. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 36 

Regional Haze SIP for Class I Areas April 4, 2008 

2018 SO2 Emissions weighted by Residence Time

Great Smoky Mtn. TN 

2018 SO2 emissions 2018 SO2 emissions

Green circles indicate 100-km and 200-km radii from Class I area.

Red line perimeter indicate Area of Influence with Residence Time > 10%.

Orange line perimeter indicate Area of Influence with Residence Time > 5%.

Max Value = 20%

Figure 4-8. Great Smoky 2018 SO2 Emissions * SO4 extinction-weighted residence time 

plots. 

To understand how emissions have changed by 2018, Figure 4-9 compares 2002 and 2018 SO2 

emissions multiplied by residence time. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 37 

Regional Haze SIP for Class I Areas April 4, 2008 

Comparison 2002 vs 2018 SO2 Emissions * Residence 

Time Using 100 m Start Height – Great Smoky Mtn., TN 

Green circles indicate 100-km and 200-km radii from Class I area.

Red line perimeter indicate Area of Influence with Residence Time > 10%.

Orange line perimeter indicate Area of Influence with Residence Time > 5%.

2002 SO2 emissions

Max Value = 46%

2018 SO2 emissions

Figure 4-9. Great Smoky Mountain 2002 vs. 2018 SO2 emissions multiplied by residence 

time. 

VISTAS states evaluated these plots of residence time weighted by sulfate extinction plots of 

gridded SO2 emissions and defined the SO2 AoIs as those areas with residence time greater than 

10%, based on trajectories with start height of 100m and 4 start times per day. 

Extinction-weighted residence plots for Class I areas indicate that the areas of probable influence 

for sulfate contribution to visibility impairment are similar to those for nitrate contribution even 

though the visibility impact of nitrate is an order of magnitude smaller than that of sulfate. From 

these plots we can initially conclude that it is appropriate to focus on sources that contribute to 

sulfate concentrations and that sources near a Class I area are more likely to contribute to 

visibility impairment than more distant sources. Gridded SO2 emissions for the sulfate 

extinction-weighted residence time plots indicate that large emissions sources at great distance 

from the Class I area can contribute to visibility impairment on some 20% worst days. However, 

it is expected that these same sources will be evaluated by Class I areas that are closer and thus 

are impacted greater. 

4.5 Importance of Pollutants Other Than Sulfate 

For completion, the following is a brief discussion of the importance of other PM components 

and contributing source categories. If NOx controls are considered, approximately 54% of NOx 

is from point sources (see Table 4.1), approximately 25% is from highway vehicles, and roughly 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 38 

Regional Haze SIP for Class I Areas April 4, 2008 

20% from nonroad engines. Elevated organic carbon (OC) and elemental carbon (EC) are 

indicators of fire. Some states may need to consider emissions from residential wood burning, 

forest fires (wild and prescribed), land clearing, and agricultural burning. 

Nitrate (NH4NO3) levels in winter can be significant and are dependent on availability of NH3; 

86% of NH3 is from area sources (e.g. agriculture). Given that sulfate contributes greater than 

70% at GRSM and JOKI on the 20% worst visibility days (Figure 4-1), the TDEC-APC believes 

it is appropriate to focus on SO2 reductions in this first Regional Haze SIP. 

4.6 Summary of Emission Inventories Used in Reasonable Further Progress (Cost Curve) 

Analysis 

A necessary component of control strategy design is a thorough review of the emission 

inventories that are used in the modeling of the future year base case. These inventories can shed 

light on the residual emissions from sources or source categories defined to be within areas of 

transport or impact of a Class I area. The most current (Base G, Fall 2006) VISTAS future year 

(2018) base case and 2002 base year emissions were used to conduct this control cost analysis. 

For purposes of listing sources within the AoI, data were provided for all sources with emissions 

over distance (Q/d) greater than 5 and maximum residence time (RTmax) greater than 5. States 

independently defined the criteria for selecting which sources from this list would be considered 

for reasonable control measures. 

The NIF formatted and SMOKE-ready modeling files for both 2002 and 2018 base year and base 

cases were obtained from VISTAS emissions development and modeling contractors and 

converted to annual emissions and summed for the geography and domain of interest. 

Tables 4-3 and 4-4 present the State breakdown of these emissions for the entire VISTAS 

domain. Because the SMOKE-ready files were used in this analysis, the particulate matter 

transport factor (0.90 times inventory values) is included in the PM emission summaries. This 

factor is applied to account for the removal of a substantial portion of fugitive dust emissions 

near a source by surrounding vegetation and structures when such emissions are used in regional 

scale modeling analyses. 

Table 4-3. VISTAS 2002 Base Year Annual Emissions Summary. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 39 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 4-4. 2018 Base Case Annual Emissions Summary. 

The review was conducted in a top down fashion starting with an analysis of the major source 

categories in the domains of interest to determine which major categories had the highest 

residual contribution to the area. Once the highest source types were identified, subcategories 

within those source types were reviewed. Again, a ranking of the highest residual sub source 

types was performed and additional analyses on these categories were conducted. Using the 

extinction weighted analysis, these emission reviews and summaries like those presented in 

Figure 4-10, VISTAS made a decision to further review only potential point sources for control. 

In addition to reviewing the residual emission categories in the future year base, it was important 

to identify reductions that had already occurred within each category or at specific units. This 

allowed VISTAS States to determine if certain source categories that had yet to be controlled 

under the future year base case had the potential for reduction. 

Finally, once each subcategory was identified, unit level tables of emission comparisons from 

2002 to 2018 were developed allowing VISTAS States to review existing emission reductions. 

These tables presented comparisons of 2002 and 2018 emission levels, for SO2, and future year 

control technology assignment (by IPM forecasting and State modification) for point sources. 

State VOC NOx CO SO2 PM-10 PM-2.5 NH3

AL 445,497 459,880 2,534,778 584,665 232,229 105,341 67,970

FL 1,291,562 930,086 7,710,376 589,069 408,902 205,450 61,643

GA 765,063 623,645 5,013,024 653,362 408,736 195,654 100,134

KY 286,752 466,403 1,730,622 580,341 148,290 50,981 57,220

MS 302,374 239,547 1,203,899 103,679 180,816 43,533 63,765

NC 655,950 616,583 4,097,444 546,429 179,242 84,513 172,976

SC 382,836 323,976 2,064,423 286,781 165,699 78,356 35,400

TN 473,244 511,151 2,601,059 442,589 165,095 75,458 42,738

VA 448,205 461,628 3,034,414 416,190 109,848 47,004 55,057

WV 135,819 348,576 802,262 569,373 48,423 27,807 12,341

VISTAS 5,187,303 4,981,474 30,792,301 4,772,477 2,047,281 914,096 669,243

BaseG Annual Emissions - 2002 Typical (Tons)

State VOC NOx CO SO2 PM-10 PM-2.5 NH3

AL 327,850 268,067 1,994,607 305,938 258,179 114,681 84,513

FL 990,629 448,443 6,099,425 260,963 483,328 226,529 73,455

GA 585,528 357,169 3,820,095 358,570 472,376 211,406 124,237

KY 236,983 277,271 1,356,496 320,525 166,918 58,559 63,959

MS 247,932 173,893 850,056 62,627 205,761 54,912 76,040

NC 421,965 275,907 2,702,315 164,067 208,015 100,253 196,577

SC 300,291 193,247 1,527,341 163,491 189,358 88,891 42,883

TN 374,093 247,827 1,692,551 228,035 187,066 84,117 46,984

VA 311,835 276,525 2,001,939 294,209 131,708 57,993 64,276

WV 107,675 150,777 576,198 190,683 54,736 31,678 14,400

VISTAS 3,904,780 2,669,125 22,621,023 2,349,107 2,357,445 1,029,017 787,325

BaseG Annual Emissions - 2018 Base Case (Tons)
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 40 

Regional Haze SIP for Class I Areas April 4, 2008 

Non-EGU unit-specific technology assignments were identified using the control efficiency 

tables provided by the VISTAS emissions inventory contractor, MACTEC. 

Ultimately, the final control strategy decisions will include the application of BART subject 

source reductions in the future year base case. 

Figure 4-10. VISTAS Base G2 SO2 Emissions Contribution by Major Source Sector. 

4.7 Process in Preparing Files for Cost Effectiveness Curve Development 

The 2018 IPM file used by VISTAS for EGU sources (RPO 2.1.9) was obtained and matched to 

the 2018 base case inventory of EGU sources. This step was conducted to ensure that 

incremental controls assigned to these source types did not duplicate existing base case 

assumptions. Because IPM does not assign a control efficiency with each control device applied 

to SO2 and NOX, some assumptions were made based on IPM documentation as to what 

pollutant specific level of reduction was applied in the future year base case runs. These 

assumptions, by primary and secondary control device code combinations for SO2, are presented 

in Table 4-5. 

Since many of the control technology control cost equations within AirControlNET require 

additional unit-level characteristic data, matches were made of the SMOKE IDA files to 

VISTAS NIF, EPA NEI, or EPA CAMD CEM data sets to obtain these variables when missing. 

Unit level boiler capacity (MMBtu/hr) or NETDC (MW) values are required for capital and 

operating and maintenance cost calculations for many of the SO2 applied technologies. In cases 

where these nameplate capacity values could not be identified, emission weighted capacities 

(based on the final EPA 2002 NEI) were assigned to boilers using a primary (highest emitting) 

Alabama

Florida

Kentucky

Georgia

Mississippi

South Carolina

North Carolina

Tennessee

Virginia

West Virginia

100

200

300

400

500

600

700

Annual SO2 (Thousand Tons)

Miscellaneous

Nonroad

Onroad

Industrial

Other Fuel Combustion

EGU

2002

2009

2018

Alabama

Florida

Kentucky

Georgia

Mississippi

South Carolina

North Carolina

Tennessee

Virginia

West Virginia

100

200

300

400

500

600

700

Annual SO2 (Thousand Tons)

Miscellaneous

Nonroad

Onroad

Industrial

Other Fuel Combustion

EGU

2002

2009

2018

Miscellaneous

Nonroad

Onroad

Industrial

Other Fuel Combustion

EGU

Miscellaneous

Nonroad

Onroad

Industrial

Other Fuel Combustion

EGU

2002

2009

2018
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 41 

Regional Haze SIP for Class I Areas April 4, 2008 

SCC. Table 4-6 presents these weighted capacities. Additionally, stack flow, sulfur content, and 

primary SCC assignment were necessary to cross-reference available incremental control 

technologies to the base case emissions inventory data. These variables were obtained where 

matches could be found, in priority order of VISTAS, CAMD, and other EPA datasets, 

respectively. 

Table 4-5. IPM Post Processing Assigned Device Codes and Applied SO2 Control 

Efficiencies. 

Primary Device Code Secondary Device Code Description CE RE 

0 0 No Control 0 0 

119 0 Dry Scrubber 90 100 

141 0 Wet Scrubber 90 100 

Table 4-6. Emissions Weighted NETDC (MW) Association.

4.8 Application of AirControlNET Technologies 

AirControlNET is a control technology analysis tool developed to support the U.S. EPA in its 

analyses of air pollution policies and regulations (Pechan, 2005). The tool provides data on 

emission sources, potential pollution control measures and emission reductions, and the costs of 

implementing those controls. 

SCC Description NETDC (MW)

10100201 

External Combustion Boilers; Electric Generation; Bituminous/Subbituminous Coal; Pulverized Coal: Wet 

Bottom (Bituminous Coal) 200

10100202 

External Combustion Boilers; Electric Generation; Bituminous/Subbituminous Coal; Pulverized Coal: Dry 

Bottom (Bituminous Coal) 500

10100203 

External Combustion Boilers; Electric Generation; Bituminous/Subbituminous Coal; Cyclone Furnace 

(Bituminous Coal) 200

10100212 

External Combustion Boilers; Electric Generation; Bituminous/Subbituminous Coal; Pulverized Coal: Dry 

Bottom (Tangential) (Bituminous Coal) 500

10100215 

External Combustion Boilers; Electric Generation; Bituminous/Subbituminous Coal; Cell Burner 

(Bituminous Coal) 1300

10100218 

External Combustion Boilers; Electric Generation; Bituminous/Subbituminous Coal; Atmospheric Fluidized 

Bed Combustion: Circulating Bed (Bitum. Coal) 200

10100222 

External Combustion Boilers; Electric Generation; Bituminous/Subbituminous Coal; Pulverized Coal: Dry 

Bottom (Subbituminous Coal) 400

10100223 

External Combustion Boilers; Electric Generation; Bituminous/Subbituminous Coal; Cyclone Furnace 

(Subbituminous Coal) 400

10100226 

External Combustion Boilers; Electric Generation; Bituminous/Subbituminous Coal; Pulverized Coal: Dry 

Bottom Tangential (Subbituminous Coal) 500

10100401 External Combustion Boilers; Electric Generation; Residual Oil; Grade 6 Oil: Normal Firing 400

10100404 External Combustion Boilers; Electric Generation; Residual Oil; Grade 6 Oil: Tangential Firing 500

10100501 External Combustion Boilers; Electric Generation; Distillate Oil; Grades 1 and 2 Oil 400

10100601 

External Combustion Boilers; Electric Generation; Natural Gas; Boilers > 100 Million Btu/hr except 

Tangential 400

10100701 External Combustion Boilers; Electric Generation; Process Gas; Boilers > 100 Million Btu/hr 200

10100801 External Combustion Boilers; Electric Generation; Petroleum Coke; All Boiler Sizes 600

10101204 External Combustion Boilers; Electric Generation; Solid Waste; Tire Derived Fuel : Shredded 200

10300811 External Combustion Boilers; Commercial/Institutional; Landfill Gas; Landfill Gas 200

20100101 Internal Combustion Engines; Electric Generation; Distillate Oil (Diesel); Turbine 200

20100109 Internal Combustion Engines; Electric Generation; Distillate Oil (Diesel); Turbine: Exhaust 200

20100201 Internal Combustion Engines; Electric Generation; Natural Gas; Turbine 200

 

 All other boilers 100
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 42 

Regional Haze SIP for Class I Areas April 4, 2008 

The core of AirControlNET is a relational database system in which control technologies are 

linked to sources within EPA emissions inventories. The system contains a database of control 

measure applicability, efficiency, and cost information for reducing the emissions contributing to 

ambient concentrations of ozone, PM10, PM2.5, SO2, NOX, as well as visibility impairment 

(regional haze) from point, area, and mobile sources. PM10 and PM2.5 as included in 

AirControlNET represent primary emissions of PM. The control measure data file in 

AirControlNET includes not only the technology's control efficiency, and calculated emission 

reductions for that source, but also estimates the costs (annual and capital) for application of the 

control measure. 

Since available versions of AirControlNET contain the preprocessed application of control 

technologies to a predetermined set of EPA emission inventories, direct use of the model in this 

analysis was not possible. However, Alpine received approval from EPA’s Innovative Strategies 

and Economics Group (ISEG) to modify the AirControlNET version 4.1 source code (Sorrels, 

2006) and data tables in order to make it useful to this study. The results of the application of 

this modified version of the code still retain the applicability, efficiency, and cost information 

from the unmodified version of the source code, but were applied to the VISTAS modeling 

inventories with updated price index scalars to reflect control costs in 2005-dollars. 

Using the modified inventories identified above, every available SO2 control strategy was 

assessed in AirControlNET against the EGU and non-EGU point source inventories to develop a 

master list of available, incremental control strategies for the entire VISTAS 36 km domain 

necessary for VISTAS States to design command-and-control or cost-effectiveness based control 

strategies by source or domain. 

4.9 Development of AoI-Based Cost Curves 

Each Class I area in the VISTAS modeling domain had an associated AoI as identified earlier in 

this document. In order to best determine where emission reduction has the greatest benefit, this 

geography was designed to limit the available source type list from including all sources within 

the entire domain. 

These marginal cost curves include the application of all available control measures to all 

applicable point sources within the AoI. The curves will allow VISTAS States to determine if, 

based on the generic application of SO2 control technologies from the associations originally 

developed in AirControlNET and improved upon with stakeholder input will help attain 

reasonable further progress emission reduction objectives while presumably minimizing the 

number and type of controlled sources in each AoI. 

Using a geocoded county list from these AoIs, the master list of incremental control measures 

was parsed from all point sources located within the boundaries of the AoIs. This parsed list was 

then sorted by incremental cost-effectiveness (marginal cost) basis to determine the most cost 

effective control suite available to attain emission reduction targets for SO2 within each AoI. 

Each individual source had its own cost effectiveness curve generated. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 43 

Regional Haze SIP for Class I Areas April 4, 2008 

In aggregate, the results of these applications are SO2 emission cost curves for all EGU and nonEGU point sources within the geographic domain of the AoI. Incremental controls on area and 

mobile sources were not considered in this analysis. 

With each AoI’s cost curve, additional metrics calculated for the distance from the emission 

release point to the Class I area IMPROVE monitor (in km), the 2018 residual emissions and 

distance (Q/d) or squared distance (Q/d^2), and the normalized 2018 SO2 point source emissions 

times distance-weighted residence time (RTMax) values for the county in which the emission 

release point was located were calculated for incremental review and consideration. The TDECAPC used these values to further determine control strategy development for individual Class I 

areas. 

5.0 REASONABLE PROGRESS ASSESSMENT 

TDEC-APC concluded that SO2 emissions from EGU and non-EGU point sources in geographic 

Areas of Influence (AoIs) are sources to consider for further controls. VISTAS developed source 

matrices for SO2 AoIs for each Class I area, using data delivered by ENVIRON for 2002 and 

2018 SO2 emissions multiplied by SO4 extinction weighted residence time plots. 

Spreadsheets were developed for each Class I area with: 

• Plant name 

• Point ID 

• Tons SO2 projected for 2018 

• Q (tons) 

• Current control efficiency, CE (%) 

• Stationary source distance to Class I area, d (km) 

• Analysis of emissions per distance from source, Q/d and Q/d2

• RT Max, the maximum percentage of time that winds pass over that area on the way to 

the Class I area on the 20% worst days 

The ranking refers to the source rank by Q/d when sources from all states are included.

In an analysis of emissions per distance from source, Q/d2

 is more representative when d is less 

than 20 km because plumes are still dispersing in two dimensions. After about 100 km, plumes 

only disperse in one dimension. The distance calculation is based on a single stack at a unit 

(when more than one are represented in the inventory) and is calculated in distance in km to the 

IMPROVE monitor at each Class I area. The residence time for the county where the source is 

located was reviewed. It was generally agreed that states would focus on those sources where 

RT max was equal to or greater than 10%. A second matrix for sources in the SO2 AoI was 

developed that combined the RTMax and Q/d metric. Using this metric, TDEC-APC calculated 

the fractional contribution from all the emission units within the SO2 AoI for each Class I area 

and identified those units with a contribution of 1% or more to the total impairment of that Class 

I area. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 44 

Regional Haze SIP for Class I Areas April 4, 2008 

Next, TDEC-APC elected to focus on those units that contributed at least 1% to sulfate visibility 

impairment at a given Class I area. This was based on several regulatory programs that use a 

higher threshold than 1% for evaluation thresholds. 

1. The BART rule specifies that a maximum impact of 0.5 dv is an acceptable threshold for 

establishing significance. This threshold equates to roughly a 5% change in visible perception. 

This same significance level is used in the Prevention of Significant Deterioration/ New Source 

Review (PSD/NSR) program for the visibility air quality related value (AQRV). 

2. The NOx SIP Call established a significance level for Section 126 petitions of 4 parts per 

billion (ppb), that being the level to which a State's contribution to another state's ozone problem 

was considered significant. This level represents approximately 3.2% of the 1-hour ozone 

standard of 125 ppb, which was the standard at the time. 

3. The CAIR rule established a PM contribution of 0.2 ug/m3 as significant. This threshold 

represents 1.3% of the Annual PM2.5 standard of 15 ug/m3. 

4. The NAAQS assign significant impact levels (SILs) for human health standards based on a 

source’s contribution to air quality. These significant levels represent a percentage of the 

NAAQS. Sources that demonstrate that their "contribution" from the new or modified sources is 

less than these significance levels do not have to complete any further modeling. TDEC-APC 

examined all the averaging periods for the criteria pollutants and determined that the 1% 

threshold contribution chosen for reasonable further progress was as stringent as any significant 

impact level, the most restrictive being the SIL for NO2 at 1 ug/m3 or 1% of the NAAQS (NO2 

NAAQS 100 ug/m3). 

Finally, TDEC-APC considered available resources to evaluate the sources in the each Class I 

area’s sulfate AoI. TDEC-APC recognized that there was neither sufficient time nor resources 

available to evaluate all units within a given AoI. Therefore, a threshold needed to be 

established to determine which units would be evaluated. Table 5-1 shows that a 1% 

contribution threshold captures greater than 60 percent of the total point source SO2 contribution 

to our two Class I areas, while requiring an evaluation of 10 to 22 units. In order to capture a 

significant percentage of the total contribution, the next increment would involve an evaluation 

of many more units. For example, at Great Smoky Mountains National Park, 10 units represent 

61 percent of the total contribution. Ninety-five units represent an additional 35% of the total 

SO2 emissions contributing to visibility impairment at the Class I area. TDEC-APC believes the 

1% threshold is appropriate, given the contribution to the total visibility impairment at each 

Class I area, and the limited resources available to conduct the unit-by-unit evaluation for 

reasonable progress.
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 45 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 5-1. Numbers and percentage of 2018 SO2 emission units that contribute to 

Tennessee Class I areas. 

 GRSM JOKI 

# Units Contributing > 1% 10 22 

Percentage of total contribution 61% 63% 

# Units Contributing > 0.1%, but < 

1% 

95 101 

Percentage of total contribution 35% 34% 

# Units Contributing < 0.1% 88 50 

Percentage of total contribution 4% 3% 

The following tables 5-2 and 5-3 show the analysis for GRSM and tables 5-4 and 5-5 for JOKI 

for sources that met the above criteria. The full spreadsheets containing all VISTAS Class I area 

results can be found in Attachment H-1. 

Table 5-2. Great Smoky Mountains Q/d, Q/d^2, RTMax, and fractional contribution 

analysis. 

(Tennessee Sources) 

 SO2 Tons CE Distance Fraction 

State

Plant 

ID Plant

Point 

ID 2002G 2018G (%)* (km) Q/d Q/d^2

RT 

Max** Q/d*RTMax Contribution

TN 0009 

TVA BULL RUN 

FOSSIL PLANT 001 36,729 8,657 90 47.31 182.97 3.87 84.37 15437.18 0.1414 

TN 0008 

ALUMINUM 

COMPANY OF 

AMERICA - SOUTH 

PLAN 16 1,856 2,370 0 16.49 143.71 8.71 83.87 12052.96 0.1104 

TN 0008 

ALUMINUM 

COMPANY OF 

AMERICA - SOUTH 

PLAN 17 1,817 2,320 0 16.49 140.69 8.53 83.87 11799.67 0.1081 

TN 0081 

A.E. STALEY 

MANUFACTURING 

COMPANY 005 3,005 2,982 4 36.00 82.83 2.30 79.99 6625.57 0.0607 

TN 0003 

EASTMAN CHEMICAL 

COMPANY 021520 16,855 16,729 4 160.39 104.30 0.65 41.30 4307.59 0.0395 

TN 0130 

APAC-TN, 

INC./HARRISON 

CONSTRUCTION DIVI 002 153 200 0 3.97 50.32 12.68 83.87 4220.34 0.0387 

TN 0020 

U.S. DEPARTMENT OF 

ENERGY, Y-12 PLANT 002 2,354 2,336 4 48.58 48.09 0.99 84.37 4057.35 0.0372 

TN 0012 

BOWATER 

NEWSPRINT & 

DIRECTORY - 

CALHOUN 015 5,232 5,871 4 82.82 70.89 0.86 57.01 4041.44 0.0370 

TN 0008 

ALUMINUM 

COMPANY OF 

AMERICA - SOUTH 

PLAN 09 424 541 0 16.49 32.80 1.99 83.87 2750.94 0.0252 

Table 5-3. Great Smoky Mountains Q/d, Q/d^2, RTMax, and fractional contribution 

analysis. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 46 

Regional Haze SIP for Class I Areas April 4, 2008 

(Outside Sources) 

 SO2 Tons CE Distance Fraction 

State Plant ID Plant

Point 

ID

(2002 

G)

(2018 

G) (%)* (km) Q/d Q/d^2

RT 

Max** Q/d*RTMax Contribution

NC 3708700159 

BLUE RIDGE 

PAPER 

PRODUCTS - 

CANTON 

MILL G-25 2,195 2,565 0 100.17 25.61 0.26 50.35 1289.46 0.0118 

Table 5-4. Joyce Kilmer Q/d, Q/d^2, RTMax, and fractional contribution analysis. 

(Tennessee Sources) 

SO2 Tons CE Distance Fraction

State

Plant 

ID Plant

Point 

ID

(2002 

G)

(2018 

G) (%)* (km) Q/d Q/d^2

RT 

Max** Q/d*RTMax Contribution

TN 0012 

BOWATER 

NEWSPRINT & 

DIRECTORY - 

CALHOUN 015 5,232 5,871 4 71.46 82.16 1.15 65.67 5395.45 0.0876 

TN 0009 

TVA BULL RUN 

FOSSIL PLANT 001 36,729 8,657 90 73.92 117.12 1.58 44.66 5230.58 0.0849 

TN 0081 

A.E. STALEY 

MANUFACTURING 

COMPANY 005 3,005 2,982 4 50.89 58.59 1.15 64.11 3756.20 0.0610 

TN 0008 

ALUMINUM 

COMPANY OF 

AMERICA - SOUTH 

PLAN 16 1,856 2,370 0 45.21 52.42 1.16 64.11 3360.65 0.0546 

TN 0008 

ALUMINUM 

COMPANY OF 

AMERICA - SOUTH 

PLAN 17 1,817 2,320 0 45.21 51.32 1.14 64.11 3290.13 0.0534 

TN 0004 

INTERTRADE 

HOLDINGS, INC. 001 1,837 2,530 4 55.89 45.26 0.81 65.67 2972.22 0.0482 

TN 0020 

U.S. DEPARTMENT 

OF ENERGY, Y-12 

PLANT 002 2,354 2,336 4 72.75 32.12 0.44 44.66 1434.48 0.0233 

TN 0003 

EASTMAN 

CHEMICAL 

COMPANY 021520 16,855 16,729 4 181.93 91.95 0.51 12.09 1111.68 0.0180 

TN 0008 

ALUMINUM 

COMPANY OF 

AMERICA - SOUTH 

PLAN 09 424 541 0 45.21 11.97 0.26 64.11 767.40 0.0125 

Table 5-5. Joyce Kilmer Q/d, Q/d^2, RTMax, and fractional contribution analysis. 

(Outside Sources) 

SO2 Tons CE Distance Fraction

State Plant ID Plant

Point 

ID

(2002 

G)

(2018 

G) (%)* (km) Q/d Q/d^2

RT 

Max** Q/d*RTMax Contribution

SC 0200-0004 

DUKE 

ENERGY:LEE 003 4,384 7,274 0 164.50 44.22 0.27 27.54 1217.82 0.0198 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 47 

Regional Haze SIP for Class I Areas April 4, 2008 

GA 07700001 

GEORGIA 

POWER 

COMPANY, 

YATES 

STEAMELECT SG07 14,024 16,530 0 229.18 72.13 0.31 16.05 1157.69 0.0188 

GA 07700001 

GEORGIA 

POWER 

COMPANY, 

YATES 

STEAMELECT SG06 15,175 16,367 0 229.18 71.42 0.31 16.05 1146.29 0.0186 

GA 20700008 

GEORGIA 

POWER 

COMPANY, 

SCHERER 

STEAM-ELE SG03 18,149 27,735 0 258.20 107.42 0.42 8.94 960.33 0.0156 

GA 20700008 

GEORGIA 

POWER 

COMPANY, 

SCHERER 

STEAM-ELE SG04 20,771 26,616 0 258.20 103.09 0.40 8.94 921.62 0.0150 

GA 20700008 

GEORGIA 

POWER 

COMPANY, 

SCHERER 

STEAM-ELE SG01 25,286 26,264 0 258.20 101.72 0.39 8.94 909.38 0.0148 

GA 20700008 

GEORGIA 

POWER 

COMPANY, 

SCHERER 

STEAM-ELE SG02 24,966 26,075 0 258.20 100.99 0.39 8.94 902.85 0.0147 

SC 0200-0004 

DUKE 

ENERGY:LEE 001 2,386 4,347 0 164.54 26.42 0.16 27.54 727.61 0.0118 

SC 0200-0004 

DUKE 

ENERGY:LEE 002 2,643 4,140 0 164.50 25.17 0.15 27.54 693.18 0.0113 

GA 01500011 

GEORGIA 

POWER 

COMPANY, 

BOWEN 

STEAMELECT SG04 42,634 6,294 90 163.76 38.44 0.23 17.63 677.70 0.0110 

NC 3708700159 

BLUE RIDGE 

PAPER 

PRODUCTS - 

CANTON 

MILL G-25 2,195 2,565 0 104.38 24.58 0.24 26.88 660.71 0.0107 

GA 01500011 

GEORGIA 

POWER 

COMPANY, 

BOWEN 

STEAMELECT SG03 42,900 6,111 90 163.76 37.32 0.23 17.63 657.95 0.0107 

AL 0008 

TVA - 

WIDOWS 

CREEK 008 9,181 10,185 90 170.64 59.69 0.35 10.74 641.07 0.0104 

Table 5-6. Numbers and percentage of 2018 SO2 emission units that contribute to Class I 

areas outside of Tennessee within 300 km. 

COHU MACA LIGO SHRO SIPS MING JARI UPBU

Total # 

Units 

Contributing 

> 1% 

23 19 19 16 19 27 12 25 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 48 

Regional Haze SIP for Class I Areas April 4, 2008 

Percentage 

of total 

contribution 

61.5 52.6 62.6 67.7 56.8 37.2 49.9 71.0 

Tennessee 

Units 

Contributing 

> 1% 

5 2 4 2 0 0 0 0 

Percentage 

of total 

contributionTN 

19.3 3.4 29.6 5.8 0 0 0 0 

The following five tables, 5-7 through 5-10, show the analysis for COHU, MACA, LIGO, and 

SHRO for sources that met the above criteria. The full spreadsheets containing all VISTAS 

Class I area results can be found in Attachment H-1. 

Table 5-7. Cohutta Q/d, Q/d^2, RTMax, and fractional contribution analysis. 

(Tennessee Sources) 

SO2 Tons CE Distance Fraction

State

Plant 

ID Plant

Point 

ID

(2002 

G)

(2018 

G) (%)* (km) Q/d Q/d^2

RT 

Max** Q/d*RTMax Contribution

TN 0012 

BOWATER 

NEWSPRINT & 

DIRECTORY - 

CALHOUN 015 5,232 5,871 4 58.30 100.71 1.73 82.90 8348.86 0.0858 

TN 0004 

INTERTRADE 

HOLDINGS, INC. 001 1,837 2,530 4 32.47 77.92 2.40 82.90 6459.57 0.0664 

TN 0009 

TVA BULL RUN 

FOSSIL PLANT 001 36,729 8,657 90 144.05 60.10 0.42 24.66 1482.07 0.0152 

TN 2730 

E. I. DU PONT DE 

NEMOURS AND 

COMPANY 0002 1,286 1,173 0 67.08 17.48 0.26 83.31 1456.26 0.0150 

TN 0081 

A.E. STALEY 

MANUFACTURING 

COMPANY 005 3,005 2,982 4 109.35 27.27 0.25 38.49 1049.62 0.0108 

Table 5-8. Mammoth Cave Q/d, Q/d^2, RTMax, and fractional contribution analysis. 

(Tennessee Sources) 

SO2 Tons Distance Fraction

State Plant

Point 

ID

(2002 

G)

(2018 

G)

CE 

(%)* (km) Q/d Q/d^2

RT 

Max** Q/d*RTMax Contribution

TN 

TVA 

CUMBERLAND 

FOSSIL PLANT 001 7,354 12,073 95 157.50 76.65 0.49 21.87 1676.34 0.0173 

TN 

TVA 

CUMBERLAND 002 9,165 11,936 95 157.56 75.76 0.48 21.87 1656.87 0.0171 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 49 

Regional Haze SIP for Class I Areas April 4, 2008 

FOSSIL PLANT 

Table 5-9. Linville Gorge Q/d, Q/d^2, RTMax, and fractional contribution analysis. 

(Tennessee Sources) 

SO2 Tons CE Distance Fraction

State

Plant 

ID Plant

Point 

ID

(2002 

G)

(2018 

G) (%)* (km) Q/d Q/d^2

RT 

Max** Q/d*RTMax Contribution

TN 0003 

EASTMAN 

CHEMICAL 

COMPANY 021520 16,855 16,729 4 81.39 205.55 2.53 84.07 17280.59 0.2429 

TN 0003 

EASTMAN 

CHEMICAL 

COMPANY 020101 1,645 1,633 4 81.67 19.99 0.24 84.07 1680.56 0.0236 

TN 0003 

EASTMAN 

CHEMICAL 

COMPANY 261501 1,163 1,202 90 81.03 14.84 0.18 84.07 1247.60 0.0175 

TN 0009 

TVA BULL 

RUN FOSSIL 

PLANT 001 36,729 8,657 90 200.32 43.22 0.22 20.14 870.45 0.0122 

Table 5-10. Shining Rock Q/d, Q/d^2, RTMax, and fractional contribution analysis. 

(Tennessee Sources) 

SO2 Tons CE Distance Fraction

State

Plant 

ID Plant

Point 

ID

(2002 

G)

(2018 

G) (%)* (km) Q/d Q/d^2

RT 

Max** Q/d*RTMax Contribution

TN 0003 

EASTMAN 

CHEMICAL 

COMPANY 021520 16,855 16,729 4 127.07 131.65 1.04 41.01 5398.97 0.0445 

TN 0009 

TVA BULL 

RUN 

FOSSIL 

PLANT 001 36,729 8,657 90 143.14 60.48 0.42 26.51 1603.32 0.0132 

Spreadsheets were developed for each Class I area source with Q/d *RTMax > 1%, indicating 

the plant name, industry description, emissions projections for 2018, current control efficiency 

(CE%), distance from Class I area, Q/d, Q/d2

, RT maximum, Q/d*RTMax, and the percentage of 

a single source contribution to the total Q/d*RT for a Class I area. Control efficiency, CE%, is 

important because it gives a sense of which facilities are already controlled by what percent and 

which may be controlled further. 

Next, an analysis of control options, generic costs of controls, and "Cost/ton" for various units 

contributing greater than 1% to any Class I area was developed. Spreadsheets containing unitlevel emissions and other associated data for the Class I areas was matched with data from 

AirControlNET (Pechan, 2005) to give SO2 control efficiency, annual SO2 emissions reduction 

from 2018 Base Case, total annualized cost (in 2005 dollars), and cost per ton reduced for 

application of specific control measures. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 50 

Regional Haze SIP for Class I Areas April 4, 2008 

The TDEC-APC reviewed the sources, emissions, control options, and costs from the SO2 AoI 

matrices and defined sources for which the Four Factor Analysis was to be conducted. The same 

few categories of point sources contribute to the majority of SO2 emissions, those being fuel 

combustion from electric utilities and fuel combustion from industrial sources, with little 

contribution from other sources. Therefore, the TDEC-APC eliminated other source categories 

from the Four Factor Analysis. The TDEC-APC next looked at source-specific costs, existing 

controls, remaining useful life, environmental and energy impacts. 

6.0 FOUR FACTOR ANALYSIS 

Section 169A(g)(1) of the Clean Air Act (CAA) and 40 CFR 51.308(d)(1)(i)(A) 

outline four statutory factors that have been identified as mandatory for purposes of establishing 

a reasonable progress goals (RPGs) for any mandatory Class I area within a State: cost of 

compliance, time necessary for compliance, energy and non-air quality environmental impacts of 

compliance, and remaining useful life of any existing source subject to such requirements. These 

statutory factors would be specific to the sources being considered for additional controls. 

6.1 The Four Statutory Factors 

6.1-1 Cost of Compliance 

The “cost of compliance” is a factor used to determine whether compliance costs for sources are 

reasonable compared to the emission reduction and visibility improvement they will achieve. 

Note that visibility improvement is not only related to tons of pollutant removed, but also 

involves how the pollutant or chemical compound affects the extinction coefficient in each Class 

I area. For example, on a pound to pound comparison, sulfate particulate impairs visibility 

greater than coarse particulate. Costs should be determined for one-time capital costs, as well as, 

ongoing annual operation and maintenance. 

6.1-2 Time Necessary for Compliance

The “time necessary for compliance” factor may be used to adjust the RPGs to reflect the degree 

of improvement achievable within the long-term strategy (LTS) period, as opposed to the 

improvement expected at full implementation of a control measure, if the time needed for full 

compliance exceeds the length of the LTS period. For instance, if implementation of a control 

measure could not be completed within the schedule outlined by the control strategy, the RPG 

should reflect what visibility improvement could be expected within the strategy period. 

For example, if construction labor availability constraints preclude the installation of controls at 

all sources of a particular category within the LTS period, the RPG should reflect the visibility 

improvement anticipated from installation of controls at the percentage of sources that could be 

controlled within the strategy period. (The SIP could still include control strategies that extend 

beyond the 2018 milestone; in the above example, the visibility improvement anticipated from 

installation of controls at the percentage of sources that could not be controlled within the first 

strategy period would have to be counted in a later SIP). 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 51 

Regional Haze SIP for Class I Areas April 4, 2008 

6.1-3 Energy and Non-Air Quality Environmental Impacts of Compliance 

The “energy and non-air quality environmental impacts of compliance” factor is meant to 

consider whether the energy requirements of the control technology result in energy penalties or 

benefits. For example, controls on diesel engines may decrease the overall efficiency and require 

a significant increase in diesel fuel consumption. The State should also consider any significant 

or unusual non-air environmental impacts, such as a waste stream that may be generated by a 

particular control technology 

6.1-4 Remaining Useful Life of the Source 

The statutory factor of the “remaining useful life of the source” is applicable only to those 

measures, which would require retrofitting of control devices (or possibly production changes) at 

existing sources. In such cases, this factor should be treated as one element of the overall cost 

analysis. For purposes of this analysis, the remaining useful life is the difference between the 

year of the reasonable progress analysis and the date the facility permanently stops operations. 

The remaining useful life of a source affects the annualized costs of retrofit controls. 

6.2 Evaluating Four Statutory Factors for Specific SO2 Emissions Sources in Each Area of 

Influence (AoI) 

The next step was to identify emission reductions that have already occurred within each source 

category and at specific units. Unit level tables of emission comparisons from 2002 to 2018 

were developed, allowing VISTAS States to review existing emission reductions. These tables 

assigned future year control technology from IPM forecasting and State modification for EGU 

and from control efficiency tables for Non-EGU point sources. 

Once emission control profiles for specific units were defined, the next step is to determine what, 

if any, additional control measures would feasibly be available, and to assign costs to those 

control measures. 

For EGUs, the 2018 IPM file used by VISTAS for EGU sources was obtained and matched to 

the 2018 base case inventory of EGU sources. This step was conducted to ensure that 

incremental controls assigned to these source types did not duplicate existing base case 

assumptions. 

For non-EGUs, VISTAS used EPA’s AirControNET database, modified for the VISTAS 

emission inventories. The core of AirControlNET is a relational database system in which 

control technologies are linked to sources within EPA emissions inventories. The system 

contains a database of control measure applicability, efficiency, and cost information for 

reducing emissions. The control measure data file in AirControlNET includes not only the 

technology's control efficiency, and calculated emission reductions for that source, but also 

estimates the costs (annual and capital) for application of the control measure. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 52 

Regional Haze SIP for Class I Areas April 4, 2008 

Using the modified inventories identified above, VISTAS ran every available SO2 control 

strategy in AirControlNET against the EGU and non-EGU point source inventories to develop a 

master list of incremental control strategies for each unit in the VISTAS 36 km domain. 

For the sources within the AOIs for each Tennessee Class I area, the master list of incremental 

control measures was sorted to determine the costs of incremental control measures. These data 

were combined in a master spreadsheet with the distance from the emission release point to the 

Class I area IMPROVE monitor (in km), the 2018 residual emissions and distance (Q/d) or 

squared distance (Q/d^2), and the normalized 2018 SO2 point source emissions times distanceweighted residence time (RTMax) values for the county in which the emission release point was 

located. Tennessee evaluated these control measures and costs (see Attachment H-2) as part of 

their review of the statutory factors for reasonable further progress. 

The Regional Haze Rule requires that states consider the following factors and demonstrate how 

these factors were taken into consideration in selecting the reasonable progress goal: 

• the costs of compliance 

• the time necessary for compliance 

• the energy and non-air quality environmental impacts of compliance, and 

• the remaining useful life of any potentially affected sources. 

6.2-1 Cost of Compliance 

Coal-fired electric utilities and coal-fired industrial boilers were the largest source categories 

contributing to SO2 in 2018 in the AoI defined for the Great Smokys and Joyce Kilmer 

Tennessee Class I areas. Industrial boilers using oil and commercial and institutional boilers 

using coal or oil had small contributions to SO2 in 2018. 

Sulfur dioxide emissions from utility, industrial, commercial, or institutional boilers can be 

controlled either by switching the fuel source to a lower sulfur fuel content or by installing postcombustion controls. Costs vary by fuel source and boiler type and require source specific 

analyses for accuracy. 

Bituminous coal is commonly burned in boilers in the eastern US. Switching to another 

bituminous coal with lower sulfur content or blending bituminous coals can reduce SO2 

emissions with least impact to boiler performance. While sub-bituminous coal has a lower sulfur 

content than bituminous coal, it also has a lower heat rate and so more coal has to be burned to 

generate the same energy output. For boilers that are designed for bituminous coal, only a small 

fraction of the fuel can be switched to low sulfur sub-bituminous coal without affecting boiler 

operations. Costs of boiler modifications to accommodate low sulfur sub-bituminous coal may 

make switching to sub-bituminous coal impractical. Contract initiation and termination costs, 

differential fuel prices and heat rates, transportation costs, and modification to boiler operations, 

fuel handling and waste handling systems will have to be considered specific to each source. 

Flue-gas desulfurization is the common post-combustion control for coal-fired boilers. Flue gas 

is passed through an absorbent for sulfur dioxide (generally limestone or lime) in either a wet 

scrubber, dry scrubber, or spray dryer. A calcium sulfate byproduct is produced that may be 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 53 

Regional Haze SIP for Class I Areas April 4, 2008 

further processed to produce gypsum as a commercial byproduct. Costs of flue-gas 

desulfurization include initial construction costs and ongoing operational and maintenance costs 

for the absorber tower, sorbent handling, and waste product handling facilities. Costs per ton 

vary with boiler size, type, and facility siting considerations. 

For oil-fired boilers, lower sulfur oil may be an option. Costs need to consider differential fuel 

prices and heat rate, boiler modifications, fuel handling costs, and maintenance costs. 

Conceptually, post-combustion controls can be used for oil boilers, but there is little precedence 

for such installations. 

6.2-2 Time Necessary for Compliance 

For fuel switching, the time necessary to terminate existing fuel contracts and initiate new 

contracts needs to be considered. Generally two to three years may be required. Instillation of 

post-combustion controls will require 3 or more years depending on market availability of labor 

and materials and utility system-wide priorities. Time necessary for compliance will need to be 

refined for specific sources. 

6.2-3 Energy and Non-Air Environmental Impacts 

Switching to lower sulfur fuel or installing post-combustion controls may reduce boiler heat rate 

and energy output. Scrubbers and spray dryers will require additional safeguards for fuel 

handling and waste handling systems to avoid additional non-air environmental impacts such as 

increased effluents in waste water discharges and storm water runoff. These factors will need to 

be considered specific to individual sources. Carbon dioxide is emitted as a byproduct of flue gas 

desulfurization, therefore impacts of increased carbon emissions will need to be considered, 

particularly if carbon emissions are limited in the future under climate change mitigation 

strategies. 

6.2-4 Remaining Useful Life 

 Remaining useful life is specific to the facility for which controls are considered. 

6.3 Process of Applying Statutory Factors 

TDEC-APC has completed the Reasonable Progress Assessment for the first Regional Haze SIP. 

The following is TDEC-APC’s Process on Reasonable Progress Assessment for the current time 

period (from the present to 2018): 

Step 1: Determine pollutants of concern. 

VISTAS evaluated the species contribution on the 20% worst visibility days and concluded that 

sulfate accounted for greater than 70% of the visibility impairing pollution. The VISTAS States 

concluded that controlling SO2 emissions was the appropriate step in addressing the Reasonable 

Progress Assessment for 2018. The VISTAS findings were consistent with the findings of the 

Southern Appalachian Mountain Initiative (SAMI). SAMI confirmed that sulfate particles 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 54 

Regional Haze SIP for Class I Areas April 4, 2008 

account for the greatest portion of the haze affecting Class I areas in the Southern Appalachian 

region and that these sulfates were produced in large part from SO2 emissions from coal 

combustion. 

Step 2: Determine which source sectors should be evaluated for reasonable progress. 

Since SO2 point source emissions in 2018 are projected to represent greater than 95% of the total 

SO2 emissions inventory, the VISTAS States concluded that the focus should be on electric 

generating unit (EGU) and non-EGU point sources of SO2 emissions. 

Step 3: Determine if the Clean Air Interstate Rule (CAIR) is sufficient for reasonable progress 

for subject EGU’s. 

TDEC-APC evaluated the amount of SO2 reduction from the EGU sector resulting from 

implementation of CAIR. The EGUs in Tennessee (Tables 6-1 and 6-2) are expected to reduce 

their SO2 emissions by approximately 75% between 2002 (2002 missions approximately 

333,884 tons per year) and 2018 (2018 emissions approximately 84,185 tons per year). 

Table 6-1. Tennessee TVA Plants Heat Input Values 

Facility Name 2006 Heat Input (mmBtu) 2006 Net Output (GWH) 

Allen 55,883,612 5,291 

Bull Run 45,085,485 4,696 

Cumberland 185,663,408 18,743 

Gallatin 75,755,960 7,524 

John Sevier 49,978,425 5,044 

Johnsonville 88,835,413 7,555 

Kingston 107,167,323 10,378 

2006 heat inputs were obtained from Acid Rain Program monitoring data, and 2006 net outputs 

were obtained from TVA. 

Table 6-2. Tennessee TVA Plants Emissions 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 55 

Regional Haze SIP for Class I Areas April 4, 2008 

To further support EGUs subject to CAIR is sufficient for reasonable progress, a discussion in 

the CAIR rule highlighted below (70 FR 25197) addresses the reasonable progress factors of cost 

and time necessary for compliance for these EGUs, and provide the necessary support for a 

State's four factor reasonable progress analysis that must accompany a State’s assertion that 

CAIR is sufficient for reasonable progress for subject EGU’s during the first planning period. 

From past experience in examining multi-pollutant emissions trading programs for SO2 

and NOX, EPA recognized that the air pollution control retrofits that result from a 

program to achieve highly cost-effective reductions are quite significant and can not be 

immediately installed. Such retrofits require a large pool of specialized labor resources, 

in particular, boilermakers, the availability of which will be a major limiting factor in the 

amount and timing of reductions. 

Also, EPA recognized that the regulated industry will need to secure large amounts of 

capital to meet the control requirements while managing an already large debt load, and 

is facing other large capital requirements to improve the transmission system. 

Furthermore, allowing pollution control retrofits to be installed over time enables the 

industry to take advantage of planned outages at power plants (unplanned outages can 

lead to lost revenue) and to enable project management to learn from early installations 

how to deal with some of the engineering challenges that will exist, especially for the 

smaller units that often present space limitations. 

Based on these and other considerations, EPA determined in the NPR that the earliest 

reasonable deadline for compliance with the final highly cost-effective control levels for 

reducing emissions was 2015 (taking into consideration the existing bank of title IV SO2 

allowances). First, the Agency confirmed that the levels of SO2 and NOX emissions it 

believed were reasonable to set as annual emissions caps for 2015 lead to highly costeffective 

controls for the CAIR region. 

Once EPA determined the 2015 emissions reductions levels, the Agency determined a 

proposed first (interim) phase control level that would commence January 1, 2010, the 

earliest the Agency believed initial pollution controls could be fully operational (in 

today's final action, the first NOX control phase commences in 2009 instead of in 2010, 

as explained in detail in section IV.C). The first phase would be the initial step on the 

Facility 

Name 

PM10 Emissions (tons) SO2 Emissions (tons) NOX Emissions (tons) 

2002 2009 2018 2002 2009 2018 2002 2009 2018 

Allen 866 981 981 19,030 21,263 21,263 14,510 2,061 2,061 

Bull Run 1,919 2,267 2,267 42,188 8,657 8,657 17,909 2,078 2,078 

Cumberland 1,831 1,690 1,690 16,661 24,009 24,009 49,939 5,762 5,762 

Gallatin 611 594 594 34,157 47,391 2,157 11,782 11,461 11,456 

John Sevier 160 151 163 35,488 32,327 1,846 10,234 10,109 1,574 

Johnsonville 5,561 2,661 2,661 108,789 22,216 22,216 23,879 13,329 1,333 

Kingston 3,574 3,766 4,056 77,571 71,120 4,037 26,089 3,238 3,633 

Emissions from 2002, 2009, and 2018 are from the VISTAS Base G/G2 emission inventory. 2002 emissions are 

based on the VISTAS 2002 actual emissions inventory. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 56 

Regional Haze SIP for Class I Areas April 4, 2008 

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. 

Although EPA's primary cost-effectiveness determination is for the 2015 emissions 

reductions levels, the Agency also evaluated the cost effectiveness of the first phase 

control levels to ensure that they were also highly cost effective. Throughout this 

preamble section, EPA reports both the 2015 and 2010 (and 2009 for NOX) cost effectiveness 

results, although the first phase levels were determined based on feasibility 

rather than cost effectiveness. The 2015 emissions reductions include the 2010 (and 2009 

for NOX) emissions reductions as a subset of the more stringent requirements that EPA is 

imposing in the second phase. 

TDEC-APC intends to re-evaluate the IPM predictions of SO2 reductions for CAIR at the time 

of the next periodic report in 2012 to ensure that the reductions currently predicted by IPM for 

CAIR are in fact taking place. Based on the evaluation of additional control measures and 

predictions by IPM under CAIR, TDEC-APC has concluded that at this time the CAIR program 

constitutes reasonable measures for Tennessee EGUs during this first assessment period 

(between baseline and 2018). 

Step 4: Determine which emission units would be evaluated based on impact. 

TDEC-APC calculated the fractional contribution from all emission units within the SO2 AoI for 

a given Class I area and identified those emission units with a contribution of 1% or more. 

Step 5: Evaluate the four factors. 

Each emission unit identified in Step 4 above was evaluated using the statutory and regulatory 

factors of 1) cost of compliance, 2) time necessary for compliance, 3) the energy and non-air 

quality environmental impacts of compliance, and 4) the remaining useful life of the emissions 

unit. TDEC-APC believes that the cost of compliance is the typically the dominant factor in 

whether a source will be required to install controls. Therefore, much emphasis was placed on 

cost of control as part of this reasonable progress assessment, as compared to the other three 

statutory factors. In addition, TDEC-APC believes that the fifth factor, visibility improvement, 

is considered by focusing the evaluation on those units that contribute at least 1% to visibility 

impairment at a given Class I area. 

For the limited purpose of evaluating the cost for the reasonable progress assessment in this first 

regional haze SIP, TDEC-APC believes it is not equitable to require non-EGUs to bear a greater 

economic burden than EGUs for a given control strategy. Using the CAIR rule as a guide, a cost 

of $2000 was used as a determiner of effectiveness. 

Based on the AoI analysis, TDEC-APC focused the reasonable progress assessments on specific 

units at the following non-EGU facilities in the State based on the 1% criteria discussed earlier in 

this document: 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 57 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 6-3. Tennessee Sources Impacting Class I Areas within 300 km 

SIGNIFICANT SOURCE IMPACTED CLASS I AREA DETERMINATION 

A.E. STALEY MANUFACTURING COMPANY (NOW TATE & LYLE) COHU, JOKI, GRSM INCORRECT DATA 

APAC-TN, INC./HARRISON CONSTRUCTION DIVI GRSM INCORRECT DATA 

BOWATER NEWSPRINT & DIRECTORY - CALHOUN COHU, JOKI, GRSM 4-FACTOR ANALYSIS 

E. I. DU PONT DE NEMOURS AND COMPANY (NOW INVISTAHIXSON/CHATTANOOGA) COHU 4-FACTOR ANALYSIS 

INTERTRADE HOLDINGS, INC. COHU, JOKI 

REMOVED FROM 

SERVICE 

U.S. DEPARTMENT OF ENERGY, Y-12 PLANT JOKI, GRSM FUEL SWITCH TO N.G. 

ALUMINUM COMPANY OF AMERICA - SOUTH PLAN JOKI, GRSM BART SOURCE 

EASTMAN CHEMICAL COMPANY JOKI, GRSM, LIGO, SHRO BART SOURCE 

TVA BULL RUN FOSSIL PLANT COHU. JOKI, GRSM, LIGO, SHRO BART SOURCE 

TVA CUMBERLAND FOSSIL PLANT MACA BART SOURCE 

A.E. STALEY MANUFACTURING COMPANY (NOW 

TATE & LYLE) 

Tate & Lyle (formerly A. E. Staley) in Loudon County significantly reduced its sulfur dioxide 

emissions and that reduction was not recognized in the inventories used to perform the VISTAS 

modeling. The company was issued a construction permit on March 9, 2007, that reduced SO2 

emissions from the boilers by approximately 62 percent. The lower SO2 emissions, (1145 tons) 

are not reflected in the VISTAS inventory for 2018. For a projected 2018 SO2 emission of 1136 

tons (1145 tons times a factor of 0.9923 - similar to the AoI 2018 emission projection procedure 

in Appendix H-1 at roughly 0.8% reduction), the source contribution at GRSM and JOKI will be 

0.024 (significant) and 0.0041 at COHU (insignificant). The source contributions were lowered 

from 6% at GRSM and JOKI to roughly 2% at each, and from initially 1% at COHU to 0.4% 

insignificant impact contribution. Due to the uncertainty in the 2018 emission projections for this 

emission unit, TDEC-APC elected to defer assessment of this facility until the next review 

period in 2018. 

APAC-TN, INC./HARRISON CONSTRUCTION DIVI 

This facility (emission unit #2) was erroneously modeled as a Ready Mix Concrete plant with 

actual SO2 emissions of 153 tons per year (2002) and projected actual 2018 SO2 emissions of 

200 tons per year, leading to a significant contribution at GRSM of 3.87%. Such source would 

have minimal SO2 emissions if any. The real SO2 source that should have been modeled is a 

Drum Mix Asphalt plant (emission unit #1) with an SO2 allowable emissions of 20.3 tons per 

year and subject to NSPS (See Appendix H-7, page 8). VISTAS AoI modeling at twice this level 

of emissions for a 2018 projection of 40.0 tons per year will lead to an AoI insignificant 

contribution of 0.0077 (or 0.8%) at GRSM [Appendix H-1, based on a distance of 3.97 km to 

GRSM, Q/d value of 10.08, RTMax value of 83.87, total contribution of 109,160.06 (Q/d * 

RTMax) from all sources at GRSM]. TDEC-APC determined that this source is insignificant 

with regard to its contribution to GRSM and no further analysis is required. 

U.S. DEPARTMENT OF ENERGY, Y-12 PLANT 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 58 

Regional Haze SIP for Class I Areas April 4, 2008 

United States Department of Energy Y-12 Plant is in the process of repowering its coal-fired boilers. 

Construction Permit # 960947F has been issued to the USDOE’s Y-12 Plant to replace the coal-fired 

boilers with natural gas fired boilers. A copy of this permit with the timing of the repowering 

appears in Appendix H-7. Compared to coal-fired emissions, the reduction in sulfur dioxide 

emissions is very significant, as natural gas has essentially no sulfur. For this reason, no further 

attempts were made to evaluate the facility under the four-factor analysis. 

INTERTRADE HOLDINGS, INC. 

This source is removed from service. Current facility permit is listed in Appendix L-12. 

TDEC-APC determined that two non-EGU sources, Bowater Newsprint in Calhoun, Tennessee 

and E.I. DuPont de Nemours (now INVISTA) in Hixson, Tennessee should be subjected to the 

four-factor analysis because those facilities contributed 1% or more to visibility impairment in a 

Class I area. Each facility was requested to perform an analysis and submit that to TDEC-APC 

for review (Attachment H-5) 

BOWATER NEWSPRINT & 

DIRECTORY - CALHOUN 

The following is a summary of the assessment for this Kraft Paper Mill (non-EGU) facility: 

Date of Bowater 4-factor analysis: October 31, 2007 

Unit on an AoI list with a FGD control option cost of $4517.00 /ton SO2 removed 

Unit Description: Three Coal-fired Boilers, using low sulfur eastern bituminous coal since 1984 

of slightly less than 1.1% sulfur content with the following specifications: 

Table 6-4. BOWATER Coal-Fired Boilers

BOILER NO. FUEL TYPE 

MAX FIRING RATE 

(MMBtu/hr) EXISTING CONTROLS 

10 Bituminous Coal 214 ESP 

11 Bituminous Coal 460 ESP, LNB 

12 Bituminous Coal 460 ESP, LNB 

The following control technology options were considered for the abovementioned Fuel Burning 

Installation unit (single common stack): 

Low sulfur Coals 

Wet Scrubbers 

Bowater evaluated switching to a lower sulfur (0.6%) western sub-bituminous coal and 

determined that is not a viable option due to the different physical properties (ash fusion 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 59 

Regional Haze SIP for Class I Areas April 4, 2008 

temperature, etc.) of western sub-bituminous coal. The physical properties of the coal are very 

important as Bowater’s boilers were designed to burn Eastern bituminous coal, not Western 

coals. Thus, switching to lower sulfur western coal is not so much a cost factor as it is a 

technologically infeasible factor. 

Bowater also evaluated installing SO2 wet scrubbers which is technically possible, but 

determined that is an expensive option for the older existing boilers at a projected cost exceeding 

$5,000 per ton of SO2 removed. Bowater also states that controls can further increase the $/ton 

of SO2 removed as the facility will be compounded with the increase in manufacturing costs due 

to the forecasted decline of 30% by 2018 in North American newsprint demand, and that will 

further reduce operations and thus actual SO2 emissions. They also contends that the VISTAS 

growth factors for 2009 and 2018 (6.7% and 16.9%, respectively) are not representative of their 

future operations due to the projected newsprint decline in the future. Bowater also discusses in 

their analysis the seasonal variability of their emissions as not being equally distributed 

throughout the year. Their months of highest coal firing correspond to the months with the best 

20% visibility (November through March), and the months of lowest coal firing correspond to 

the months with the worst 20% visibility (June through September). 

Bowater states that the remaining useful life of the power boilers exceeds the useful life of any 

potential SO2 control equipment . However, the remaining useful life of the facility’s five paper 

machines supported by the power boilers may be considerably shorter than the life of any 

potential SO2 controls. Three of the five paper machines at the facility were built in the 1950’s, 

while the remaining two were built in the 1980’s. Based upon market forecasts for newsprint in 

North America, Bowater believes that the older 1950 vintage machines may be permanently shut 

down in the future. These less efficient machines require more hot water from the boilers to be 

produced. If they are shut down, less coal will be burned and less visibility impairing emissions 

will be produced. This does not mean that the boilers will be shut down; it merely means that 

they will not be operated at a higher capacity. Other environmental factors impacting the 

application of wet scrubbers are the water scarcity in the local area due to seasonal droughts and 

wastewater/sludge treatment and disposal. 

Bowater further states that the VISTAS 2002 emission inventory and modeling utilized an 

erroneous emission rate (177,579 tons) based on 1.5% sulfur in the coal as opposed to 1.1% 

sulfur currently using and 140,000 tons per year current emissions. This translates into 42% or 

2,135 tons of SO2 reductions per year. Additionally, the kraft mill non-condensible TRS gases 

are no longer burned in the power boilers, thus reducing SO2 emissions by another 170 tons per 

year. 

E. I. DU PONT DE NEMOURS AND COMPANY (NOW 

INVISTA-HIXSON/CHATTANOOGA) 

The following is a summary of the assessment for this non-EGU facility: 

Unit on an AoI list with a FGD control option cost of $8162 /ton SO2 removed 

 Three Coal-fired Boilers, Emission unit EU-002, with the following specifications: 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 60 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 6-5. INVISTA Coal-Fired Boilers

BOILER NO. FUEL TYPE 

MAX FIRING RATE 

(MMBtu/hr) EXISTING CONTROLS 

3 Bituminous Coal 65 Baghouse 

4 Bituminous Coal 150 Baghouse 

5 Bituminous Coal 150 Baghouse 

The following control technology options were considered for the above mentioned emission 

points: 

Low sulfur Coals 

Wet FGD (Wet Scrubbers) 

Spray Dryer Absorber (SDA) System 

Fluidized Bed Combustion (FBC) with Limestone 

Dry Sorbent Injection (DSI) System 

The current SO2 emissions averaged at 944 tons/yr over three years (2004, 2005, and 2006) from 

these boilers. Current Title V permit limits coal sulfur content to 1.25%, however, actual sulfur 

content has averaged nearly 1.0% over the last three years. 

INVISTA evaluated switching to a lower sulfur (0.75%) western sub-bituminous coal and 

determined that is a viable option, however, to calculate cost-effectiveness, the change in 

emissions must be determined. The decrease in SO2 emissions from the baseline was calculated 

to be approximately 214 tons per year. The cost-effectiveness was calculated to be approximately 

$1,225 per ton of SO2 removed. Low sulfur coal is a commodity that is experiencing increasing 

market denmand and thus increasing costs. 

A Wet FGD is determined to be technically feasible option for control of SO2 emissions from 

EU-002. The TCI (capital cost) for the Wet FGD is estimated at $11,445,390 with an estimated 

TAC (operating and maintenance) cost of $3,046,633 based on an interest rate of 8.0% and an 

economic lifetime of 10 years. At 92% efficiency and 944 tons baseline, the estimated emitted 

SO2 emissions would be 76 tons per year. The cost-effectiveness was calculated to be 

approximately $3,508 per ton of SO2 removed. Additional costs associated with installing a 

separate stack due to problems associated with the presence of a persistent , highly opaque steam 

plume from the scrubbers’stacks making this option even less cost-effective. 

An SDA system was determined to be technically feasible as a control option. However, this 

option could result in an overall ash with properties so different from the current that it will no 

longer be acceptable for use in cement kiln. If that becomes the case, the ash and spent reactant 

mixture would have to be trucked offsite for disposal in a landfill at a substantial increase in cost 

relative to the current disposal. The cost-effectiveness of applying SDA to EU-002 is estimated 

to be at least $4,000 per ton of SO2 removed. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 61 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 6-6. INVISTS Extract From EPA Table 1A (EPA-F/452-03-34) 

 for Boilers<2,000 MMBtu/hr 

CAPITOL COST 

($/MMBtu/hr) 

O&M COST 

($/MMBtu/hr) 

ANNUAL COST 

($/MMBtu/hr) 

COST OF SO2 

REMOVED 

($/TON) 

30,000 – 150,000 1,000 – 30,000 10,000 – 50,000 500 – 4,000 

The DSI system was determined to be technically feasible as a control option. However, this 

option could result in an overall ash with properties so different from the current that it will no 

longer be acceptable for use in cement kiln. If that becomes the case, the ash and spent reactant 

mixture would have to be trucked offsite for disposal in a landfill at a substantial increase in cost 

relative to the current disposal. The TCI for this system is estimated at $4,700,000 with an 

estimated TAC cost of $1,905,890 based on an interest rate of 8.0% and an economic lifetime of 

10 years. At 50% efficiency and 944 tons baseline, the estimated removed SO2 emissions would 

be 472 tons per year. The cost-effectiveness of applying DSIO to EU-002 is estimated to be at 

least $4,037 per ton of SO2 removed. 

Table 6-7. INVISTA SUMMARY OF CONTROLS 

CONTROL 

OPTION 

COST OF SO2 REMOVED 

($/TON) 

LOW SULFUR COAL 1,225 

WET FGD/SCRUBBBER 3,508 

SDA SYSTEM 4,000 

DSI SYSTEM 4,037 

Table 6-8. INVISTA TIME FOR COMPLIANCE

CONTROL 

OPTION 

TIME TO IMPLEMENT 

LOW SULFUR COAL 1 YEAR 

WET FGD/SCRUBBBER 3 YEARS 

SDA SYSTEM 3 YEARS 

DSI SYSTEM 3 YEARS 

Table 6-9. INVISTA ENERGY & NON-AIR ENVIRONMENTAL IMPACTS 

CONTROL OPTION ENERGY IMPACTS 

NON-AIR QUALITY 

ENVIRONMENTAL 

IMPACTS 

LOW SULFUR COAL 

May have to be shipped from 

greater 

Distances, resulting in additional 

fuel usage. None Identified 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 62 

Regional Haze SIP for Class I Areas April 4, 2008 

WET FGD/SCRUBBER 

Additional fuel usage to transport 

lime to Facility, increased 

electricity usage for lime handling, 

recirculation pumps, and to 

overcome increased pressure drop 

across scrubbers. Potential for 

increased fuel usage if stack 

reheaters are needed to reduce 

steam plumes 

Use of substantial quantities of 

fresh water. Generation of 

substantial quantities of industrial 

wastewater containing suspended 

and dissolved solids requiring 

disposal 

SPRAY DRYER ABSORBER (SDA) 

SYSTEM 

Additional fuel usage to transport 

lime to Facility, increased 

electricity usage for lime handling, 

recirculation pumps, and to 

overcome increased pressure drop 

in absorption chamber and 

baghouse. Potentially increased 

fuel and electricity usage if fly ash 

must be disposed of at the landfill. 

Potential for increased fuel usage 

if stack reheaters are needed to 

reduce steam plume. 

Use of substantial quantities of 

fresh water. Potential for 

degradation in quality of water 

discharged from ash pond outfall 

due to lime and dissolved solids 

Potentially substantial increase in 

solid waste generation and 

disposal if fly ash cannot be 

recycled. 

DRY SORBENT INJECTION (DSI) 

SYSTEM 

Additional fuel usage to 

transport lime to Facility, 

increased electricity usage for 

lime injector and due to 

increased pressure drop in 

baghouse. Increased fuel and 

electricity usage due to 

disposal of fly ash at the 

landfill. 

Substantial increase in solid waste 

generation and disposal associated 

with flyash and spent reactant. 

Results of the four-factor analysis:

Bowater Newsprint

Bowater Newsprint operates three coal-fired power boilers that constitute the bulk of its facility 

SO2 emissions. Bowater presented information and data in its four-factor analysis that lead 

TDEC-APC to conclude that it should not have to install SO2 post combustion controls nor 

switch to lower sulfur fuels during this first regional haze SIP review period. The information in 

their four factor analysis states that the emissions in the VISTAS modeling inventory are 

overstated and that the growth projections for that particular facility are in excess of what is 

likely to occur for a paper mill that age. TDEC-APC is making a formal declaration that 

additional SO2 reductions at Bowater Newsprint are not needed during this first regional haze 

SIP review period. This declaration does not constitute a determination that additional SO2 

reductions at Bowater Newsprint will not be required for any subsequent regional haze SIP 

review period beyond 2018, nor does it constitute such a determination for any other regulatory 

program or requirement. 

INVISTA
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 63 

Regional Haze SIP for Class I Areas April 4, 2008 

INVISTA operates three coal-fired boilers that constitute the bulk of its SO2 emissions. 

INVISTA presented an argument that switching to lower sulfur coal at a cost of $1,225 per ton 

control costs was un-justifiable as the cost estimates were based upon the current cost of low 

sulfur coal. INVISTA argued, and TDEC-APC agreed, that with fuel-switching becoming a 

favored option among a number of sources for a number of air pollution control reasons, the 

future cost of a coal switch could be potentially cost prohibitive. For this reason, TDEC-APC 

deferred requiring the company to switch during this review period until future low sulfur fuel 

costs were more finite in the next review period. TDEC-APC notes that 2018 predicted visibility 

impairment values for the Class I areas in the vicinity of INVISTAS are well below the uniform 

rate of progress glide slopes as further justification for deferring fuel switching in this current 

review period. 

 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 64 

Regional Haze SIP for Class I Areas April 4, 2008 

7.0 Best Available Retrofit Technology 

7.1 Background

As required by the CAA, the EPA included in the final regional haze rule a requirement for Best 

Available Retrofit Technology (BART) for certain large stationary sources that were placed in 

operation between 1962 and 1977. The BART-eligible sources are those sources which have the 

potential to emit 250 tons or more of a visibility-impairing air pollutant, were placed in operation 

between August 7, 1962 and August 7, 1977, and whose operations fall within one or more of 26 

specifically listed source categories. Under the CAA, BART is required for any BART-eligible 

source that a State determines ‘‘emits any air pollutant which may reasonably be anticipated to 

cause or contribute to any impairment of visibility in any such area.’’ Accordingly, for stationary 

sources meeting these criteria, States must address the BART requirement when they develop 

regional haze SIPs. The EPA has set guidance for identifying BART-eligible sources in 40 CFR 

Part 51 Appendix Y. 

A BART-eligible source that is responsible for a 1.0 deciview (dv) change or more is considered 

to “cause” visibility impairment. Although the appropriate threshold may vary, the EPA’s 

guidance states that the contribution threshold used for BART applicability should not be higher 

than 0.5 deciviews. Thus a BART-eligible source that is responsible for a 0.5 dv change or more 

is considered to “contribute” to visibility impairment. Any source determined to cause or 

contribute to visibility impairment in any Class I area is subject to BART. 

The guidelines direct that States should include SO2, NOx, and direct particulate matter (PM) 

emissions, including both PM10 and PM2.5, in determining whether sources cause or contribute 

to visibility impairment. States may use their best judgment to determine whether VOC or 

ammonia emissions are likely to have an impact on visibility in an area.

Sources that are subject to BART must undergo a BART determination. Section 169A(g)(7) of 

the CAA requires that States must consider the following factors in making BART 

determinations: (1) The costs of compliance, (2) The energy and non-air quality environmental 

impacts of compliance, (3) Any existing pollution control technology in use at the source, (4) 

The remaining useful life of the source, and (5) The degree of improvement in visibility which 

may reasonably be anticipated to result from the use of such technology. 

See Appendix L for a full discussion of the BART process used for the Regional Haze SIP. 

7.2 Summary of BART Determinations 

In Tennessee, there were twelve facilities identified with BART-eligible sources. Of these 

twelve sources, eight were exempt from BART through modeling. For a list of BART-eligible 

facilities please refer to Appendix L. The four remaining sources were unable to demonstrate 

less than a 0.5 dv impact on one or more Class I areas. Alcoa , Inc.- Tennessee Operations, 

located in Alcoa, Tennessee was determined to impact Great Smoky Mountains National Park 

and Joyce Kilmer – Slickrock Wilderness Area. E. I.duPont de Nemours and Company (DuPont)

located in Old Hickory, Tennessee was determined to impact Mammoth Cave National Park 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 65 

Regional Haze SIP for Class I Areas April 4, 2008 

Eastman Chemical located in Kingsport, Tennessee was determined to impact Great Smoky 

Mountains National Park, Linville Gorge National Wilderness Area, Joyce Kilmer – Slickrock 

Wilderness Area, James River Face Wilderness Area, Shining Rock Wilderness Area, and 

Cohutta Wilderness Area. TVA-Cumberland located in Cumberland, Tennessee was determined 

to impact Mammoth Cave National Park and Sipsey National Wilderness Area. 

These four facilities were subject to the Tennessee BART rule and were required to submit a 

permit application proposing BART for their sources. The proposed BART determinations were 

shared with the EPA and the FLMs for their review and comment. 

The TDEC-APC reviewed the proposed BART determinations and has concluded that BART for 

Alcoa is limiting the sulfur in the calcined petroleum coke used to manufacture anodes to 3%. 

TDEC-APC concluded that BART for Eastman Chemical is the application of SDA/FF-dry fluegas desulfurization using a Spray Dryer Absorber (SDA) followed by a fabric filter for the five 

Coal-fired Boilers #25-#29 (B-253). 

TDEC-APC concluded that BART for TVA-Cumberland is no additional controls. 

TDEC-APC concluded that BART for DuPont-Old Hickory is limiting the total combined daily 

emissions for Boilers 20 and 24 based upon the following operating limits stated in Table 7.2 

below. 

 

Table 7.2 DuPont-Old Hickory BART Control Determination–Emission Limitations 

Operating Limits SO2 (lb/day) NOx (lb/day) 

Summer Months (May-September) 32260 6120 

NON-Summer Months (October -April) 38570 6770 

For a full discussion of the BART subject sources please refer to Appendix L. 

8.0 FINAL LONG TERM STRATEGY (LTS) AND REASONABLE 

PROGRESS GOALS (RPGs) 

As stated in section 2.0 above, the Regional Haze Rule (RHR) requires States to establish 

Reasonable Progress Goals (RPGs), expressed in deciviews (dv), for visibility improvement at 

each affected Class I area covering each (approximately) 10-year period until 2064. This first set 

of RPGs must be met through measures contained in the state’s LTS covering the period from 

the baseline until 2018. This section discusses development of Tennessee’s LTS. 

8.1 Long-Term Strategy (LTS) 

Ammonium sulfate is the most important contributor to visibility impairment and fine particle 

mass on the 20% worst and 20% best visibility days at Great Smokys and Joyce KilmerSlickrock Tennessee Class I areas. Sulfate levels on the 20% worst days account for greater than 

70% of the visibility impairment. Across the VISTAS region, sulfate levels are higher at the 

Southern Appalachian sites than at the coastal sites. On the 20% clearest days, sulfate levels are 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 66 

Regional Haze SIP for Class I Areas April 4, 2008 

more uniform across the region. Reduction of SO2 emissions would be the most effective means 

of reducing ammonium sulfate. Greater than 95% of SO2 emissions in Tennessee are 

attributable to EGUs and industrial point sources. Thus, the LTS for this first Regional Haze SIP 

focused on reductions in SO2 emissions. 

In Tennessee and across the region there are significant control programs in place to reduce 

SO2 emissions between the baseline period and 2018. Most notably, CAIR is predicted to 

result in approximately 75% reduction from EGU SO2 emissions in Tennessee (Table 6-2). 

Overall the SO2 emissions in Tennessee are predicted to decrease from 2002 levels at 442,589 

tons per year to 228,035 tons per year in 2018 (Table 4-3). Such large SO2 reductions are 

predicted to result in significant improvements in visibility. 

At the two Class I areas in Tennessee, Great Smokys and Joyce Kilmer-Slick rock, visibility 

improvements on the 20% worst days are expected to be better than the uniform rate of progress 

glidepath by 2018 (Figures 2-2 and 2-3) based solely on reductions from existing and planned 

emissions controls. For example, at Great Smoky Mountains, a 4.5 deciview improvement in 

visibility would meet uniform rate of progress in 2018; expected emissions reductions by 2018 

Base Best & Final (B&F) are projected to achieve a 6.8 deciview improvement. In fact, 

visibility improvements at all of the VISTAS mountain Class I areas and most of the coastal 

Class I areas are projected to be better than the uniform rate of progress. 

In addition to improving visibility on the 20% worst visibility days, states are also required to 

protect visibility on the 20% best days at the Class I areas. Visibility on the 20% best days is 

projected to improve in 2018 at all VISTAS Class I areas as a result of the 2018 Base B&F 

emissions reductions. The percentage of the target achieved for the Great Smokys and Joyce 

Kilmer-Slickrock Tennessee Class I areas is about –10.8% (Figure 8-1). Zero percent change 

would mean no change in visibility; -10% means that visibility is better than no change, or a 10% 

improvement (values lower than current conditions.) 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 67 

Regional Haze SIP for Class I Areas April 4, 2008 

Figure 8-1. Reasonable progress assessment for 20% best days at 

Great Smoky Mountains National Park 

Visibility Improvement at Joyce Kilmer Wilderness is represented by Great Smoky Mountains. 

TDEC-APC completed a reasonable progress assessment after modeling the Clean Air Act 

controls discussed above. The assessment did not identify any cost effective control measures 

for the SO2 non-EGU units that contributed greater than 1% to visibility impairment at any of 

the Class I areas in Tennessee or in neighboring States. TDEC-APC concluded that the required 

reductions from the CAIR requirements were reasonable for this LTS. 

8.2 What Additional Emissions Controls Were Considered as Part of the Long-Term 

Strategy for Visibility Improvement by 2018? 

Section 308(d)(3)(v) of the regional haze rule lists several factors that must be addressed in each 

SIP. These factors include the role of fire at Class I areas and status of state planning for smoke 

management, the role of dust and fine soil at Class I areas and status of state plans to mitigate 

emissions from construction activities, and the role of NH3 and potential benefits if emissions 

from agricultural sources were mitigated. 

As discussed in Section 4.1 and demonstrated in Figure 4-1, elemental carbon (sources include 

agriculture, prescribed wildland fires, and wildfires) is a relatively minor contributor to visibility 

impairment at the Class I areas in Tennessee. However, TDEC-APC is currently working to 

develop a smoke management program that addresses the issues laid out in EPA’s 1998 draft 

guidance for smoke management plans. 

Also as discussed in Section 4.1 and demonstrated in Figure 4-1, fine soils are a relatively minor 

contributor to visibility impairment at the Class I areas in Tennessee. Nevertheless, in regard to 

construction activities, the Tennessee Department of Transportation (TDOT) has issued 

regulations addressing control of erosion, siltation, and pollution from construction activities. 

Reasonable Progress Assessment 

Great Smoky Mountains - 20% Best Days

New Improve Equation, 12 km grid

13.58 13.58 13.58

13.11 12.11

4.54

0

5

10

15

20

25

30

35

200

0

200

4

200

8

201

2

201

6

202

0

202

4

202

8

203

2

203

6

204

0

204

4

204

8

205

2

205

6

206

0

206

4

Year

Haziness Index (Deciviews)

Baseline Natural Condition (20% Best Days) Observation Method 1 Prediction

Uniform rate of progress = 2.11 dv by 2018
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 68 

Regional Haze SIP for Class I Areas April 4, 2008 

In addition, TDEC-APC currently having a Fugitive Dust Emissions Control rule, TAPCR 

Chapter 1200-3-8 (the citation of this rule is offered only for reference purposes and it is not 

offered for inclusion into the Tennessee Regional Haze SIP.), to control particulates from 

fugitive dust emission sources generated within plant boundaries from activities such as 

“unloading and loading areas, process areas, stockpiles, stock pile working, plant parking lots, 

and plant roads (including access roads and haul roads).” Copy of this rule is included as 

Attachment H-6. 

In regard to agricultural ammonia, TDEC-APC has no regulations. 

8.3 Reasonable Progress Goals (RPGs) 

The Regional Haze Rule (RHR) at 40 CFR section 51.308(d)(1) requires States to establish 

RPGs for each Class I area within the state (expressed in deciviews) that provide for reasonable 

progress towards achieving natural visibility. In addition, EPA published the final “Guidance for 

Setting Reasonable Progress Goals under the Regional haze Rule” on June 1, 2007 to use in 

setting RPGs (Attachment H-4). 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 State 

Implementation Plan (SIP) period. The state must also provide an assessment of the number of 

years it would take to attain natural visibility conditions if improvement continues at the rate 

represented by the RPGs. 

In accordance with the requirements of 40 CFR §51.308(d)(1), this Regional Haze SIP 

establishes RPGs for the Great Smokys and Joyce Kilmer-Slickrock Class I areas in Tennessee. 

To calculate the rate of progress represented by each RPG, TDEC-APC compared baseline 

visibility conditions to natural visibility conditions in each Tennessee class I area and determined 

the uniform rate of visibility improvement (in deciviews) that would need to be maintained 

during each implementation period in order to attain natural visibility conditions by 2064. The 

TDEC-APC has summarized expected visibility improvements under existing federal and state 

regulations, BART determinations in Tennessee and neighboring states, and any additional 

control measures found to be reasonable to implement in this review period. These controls will 

be modeled in CMAQ as part of the Long-Term Strategy (LTS). At this time TDEC-APC has 

determined that the RPGs will be at least as stringent as the uniform rate of progress “glidepath”. 

VISTAS has already demonstrated that the 2018 Base B&F control scenario provides for an 

improvement in visibility better than the uniform rate of progress for the Great Smokys and 

Joyce Kilmer-Slickrock for the most impaired days over the period of the implementation plan 

and ensures no degradation in visibility for the least impaired days over the same period. In 

addition, it is expected that IMPROVE monitoring results for 2018 will at that time be used to 

establish a new baseline for the next planning period. 

In addition, because Great Smoky Mountain National Park and Joyce Kilmer-Slickrock are split 

between Tennessee and North Carolina, the TDEC-APC and the North Carolina Division of Air 

Quality (NCDAQ) have agreed to work together in setting RPGs. Note that TDEC-APC and 

NCDAQ have been working together through VISTAS throughout the regional haze SIP 

planning process. Table 8-1 lists Tennessee’s RPGs. 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 69 

Regional Haze SIP for Class I Areas April 4, 2008 

Table 8-1. Reasonable Progress Goals ( RPGs) for Tennessee Class I Areas 

(2018 Base Best&Final) 

Class I Area Baseline 

Visibility 

(deciviews) 

RPG (Deciview 

Improvement 

Expected by 

2018, 20% Worst 

Days) 

RPG (Deciview 

Improvement 

Expected by 

2018, 20% Best 

Days) 

Deciview 

Improvement 

Needed 2018-

2064 (20% Worst 

Days) 

Great Smoky 

Mountains 

National Park 

30.28 6.78 1.47 12.11 

Joyce KilmerSlickrock 

Wilderness 

30.28 6.78 1.47 12.11 
Reasonable Progress Evaluation/Long Term Strategy Appendix H - 70 

Regional Haze SIP for Class I Areas April 4, 2008 

REFERENCES: 

1. Boylan Ph.D., James, 2006, VISTAS Joint Tech Analysis-Planning Call. Power Point 

Presentation: Summary BART_VOC_NH3_PM.ppt. 

2. Brewer, P.F.; and Adloch, J.P., 2005, Trends in Speciated Fine Particulate Matter and 

Visibility across Monitoring Networks in the Southeastern United States. J Air and Waste 

Management Association, 55, 1663-1674. 

3. Federal Register / Vol. 70, No. 128 / Wednesday, July 6, 2005 / Rules and Regulations. 

4. Hand, J.L.; and Malm, W.C.,2006, Review of the IMPROVE Equation for Estimating 

Ambient Light Extinction Coefficients - Final Report. March 2006. Prepared for 

Interagency Monitoring of Protected Visual Environments (IMPROVE), Colorado State 

University, Cooperative Institute for Research in the Atmosphere, Fort Collins, CO. 

5. MACTEC, 2006, Documentation of the Base G 2002 Base Year, 2009 and 2018, 

Emissions Inventory VISTAS. 

6. Pechan, E.H., and Associates, Inc., 2005, AirControlNET User Guide. 

7. Pitchford, Marc., 2006, Natural Haze Levels II: Application of the New IMPROVE 

Alogrithm to Natural Species Concentrations Estimates. Final Report of the Natural 

Haze Levels II Committee to the RPO Monitoring/Data Analysis Workgroup. Sep 2006. 

8. Sorrels, Larry, 2006, AirControlNET 4.1 Software; US EPA, OAQPS, Research Triangle 

Park, North Carolina. 

9. U.S. Environmental Protection Agency. (2003). Guidance for Tracking Progress under 

the Regional Haze Program; EPA-54/B-03-004, 2003.