1 

Technical Support Document for 

Tennessee Regional Haze SIP Submittal 

April 2011 

Prepared and Reviewed by: 

John Calcagni 

Brenda Johnson 

Rick Gillam 

Michele Notarianni 

U.S. EPA – Region 4 Atlanta, GA 
2 

Technical Support Document (TSD) for 

Tennessee Regional Haze SIP Submittal 

Table of Contents 

I. Background 

II. Summary of EPA’s Action 

III. Evaluation of Regional Haze Submittal 

A. Identification of Areas 

B. Reasonable Progress Goals (RPGs) Development 

1. Calculations of Baseline Visibility Conditions 

2. Calculations of Natural Visibility Conditions 

3. Uniform Rate of Progress (UROP or “Glidepath”) 

for Reasonable Progress 

C. Long-Term Strategy (LTS) 

1. Technical Basis for Strategy 

2. Identification of Sources and Factors to be 

Considered for Reasonable Progress 

3. Source or Source Category Specific Analyses for 

Reasonable Progress 

4. Enforceability of Reasonable Progress Measures 

D. Best Available Retrofit Technology (BART) Requirements 

1. Identification of all BART-Eligible Sources 

2. Modeling or other Demonstrations for BART 

Exempt Sources 

3. Identification of Sources Addressed by Clean Air 

Interstate Rule (CAIR) 

4. Source Specific BART Determinations 

5. Enforceability of BART 

E. Coordination of Regional Haze and Reasonably 

Attributable Visibility Impairment (RAVI) Requirements 

F. Monitoring Strategy and Other Implementation 

Requirements 

G. Emission Inventory 

IV. Conclusions 

_____________________________________________________________________ 

Note: Italicized text in this document that appears under the “State Regional Haze 

Submittal” headings are excerpts from relevant portions of the Tennessee regional haze 

submittal as cited. Figure and table citations under these headings reflect the actual 

references as listed in the State’s SIP submittal. Page numbers refer to the SIP Narrative, 

unless otherwise specified.
3 

TSD for Tennessee Regional Haze SIP Submittal 

I. Background 

In Section 169A of the 1977 Amendments to the Clean Air Act (CAA), Congress set 

forth a program for protecting visibility in Federal Class I areas which calls for the 

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

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

Congress adopted the visibility provisions to protect visibility in 156 Federal Class I 

areas, which include certain national parks, memorial parks, and wilderness areas over a 

certain size, and all international parks. These areas are defined at 40 CFR 81.400, and 

listed by State at 40 CFR 81.401-81.437. On December 2, 1980, EPA promulgated 

regulations to address visibility impairment that is “reasonably attributable” to a single 

source or small group of sources. (45 FR 80084) These regulations represented the first 

phase in addressing visibility impairment and deferred action on regional haze that 

emanates from a variety of sources until monitoring, modeling and scientific knowledge 

about the relationships between pollutants and visibility impairment improved. 

In the 1990 Amendments to the CAA, Congress added Section 169B and called on EPA 

to issue Regional Haze rules. The Regional Haze Rule (“RHR”) that EPA promulgated 

on July 1, 1999 (64 FR 35713) revised the existing visibility regulations to integrate 

provisions addressing regional haze visibility impairment and establish a comprehensive 

visibility protection program for Federal Class I areas. States are required to submit state 

implementation plans (SIPs) to EPA that set out each state’s plan for complying with the 

RHR, including consultation and coordination with other states and with Federal Land 

Managers (FLMs). States must submit a regional haze SIP to EPA within three years 

after the date of designation of areas under the National Ambient Air Quality Standard 

(NAAQS) for fine particulate matter (PM2.5). EPA promulgated PM2.5 designations on 

December 17, 2004, and thus, regional haze SIPs were to be submitted to EPA by 

December 17, 2007, which is also specified at 40 CFR 51.308(b). 

The RHR addressed the combined visibility effects of various pollution sources over a 

wide geographic region. Consequently, all 50 states, including those without Class I 

areas, Washington, D.C., and the Virgin Islands, are required to submit Regional Haze 

SIPs. (40 CFR 51.300(b)(3)). The US EPA designated five Regional Planning 

Organizations (RPOs) to assist with the coordination and cooperation needed to address 

the visibility issue. The RPO that makes up the southeastern portion of the contiguous 

United States is known as VISTAS (Visibility Improvement – State and Tribal 

Association of the Southeast). VISTAS members include: the Eastern Band of the 

Cherokee Indians, other Federally Recognized Tribes and Local Air Programs within the 

geographic area, and the following states: Alabama, Florida, Georgia, Kentucky, 

Mississippi, North Carolina, South Carolina, Tennessee, Virginia, and West Virginia. The 

State of Tennessee Department of Environment and Conservation through the Tennessee 

Division of Air Pollution Control (TDEC-APC) chose to participate in VISTAS to 

develop the technical analyses needed to fulfill the requirements of the RHR. 
4 

 Figure 1. Geographical Areas of Regional Planning Organizations 

 

 Figure 2. Class I Areas in the VISTAS Region 
5 

II. Summary of Action 

EPA is proposing a limited approval and a limited disapproval of a revision to the 

Tennessee State Implementation Plan (SIP) submitted by the State of Tennessee through 

the Tennessee Department of Environment and Conservation (TDEC) on April 4, 2008, 

that addresses regional haze for the first implementation period. This revision addresses 

the requirements of the Clean Air Act (CAA) and EPA’s rules that require states to 

prevent any future and remedy any existing anthropogenic impairment of visibility in 

mandatory Class I areas caused by emissions of air pollutants from numerous sources 

located over a wide geographic area (also referred to as the “regional haze program”). 

States are required to assure reasonable progress toward the national goal of achieving 

natural visibility conditions in Class I areas. EPA is proposing a limited approval of this 

SIP revision to implement the regional haze requirements for Tennessee on the basis that 

the revision, as a whole, strengthens the Tennessee SIP. Also in this action, EPA is 

proposing a limited disapproval of this same SIP revision because of the deficiencies in 

the State’s April 2008 regional haze SIP submittal arising from the remand by the U.S. 

Court of Appeals for the District of Columbia (D.C. Circuit) to EPA of the Clean Air 

Interstate Rule (CAIR).
6 

III. Evaluation of Regional Haze Submittal 

A. Identification of Areas 

The Plan must identify each mandatory Class I Federal area located within the state and 

in each mandatory Class I Federal area located outside the state that may be affected by 

emissions from within the state. Where a mandatory Class I Federal area is in multiple 

states, a description of how the states have assigned responsibilities for the area needs to 

be included. 

State Regional Haze Submittal 

Pages 4-6 

Tennessee has two Class I areas within its borders: Great Smoky Mountains National 

Park and Joyce Kilmer-Slickrock Wilderness Area. TDEC-APC is responsible for 

developing the Regional Haze SIP for Tennessee and submitting it to the Tennessee Air 

Pollution Control Board for approval. This SIP establishes reasonable progress goals 

for visibility improvement at each of these Class I areas, and a long-term strategy that 

will achieve those reasonable progress goals within the first regional haze planning 

period. The Great Smoky Mountains and Joyce Kilmer – Slickrock are located in both 

Tennessee and North Carolina. For the Great Smoky Mountains, both states are sharing 

the lead for setting goals and for Joyce Kilmer – Slickrock, North Carolina is the lead. 

Figure 1.4-1. Tennessee Class I areas 

EPA Findings: Tennessee has appropriately addressed this provision. 

Great Smoky Mountains National Park

Joyce KilmerSlickrock
7 

III. Evaluation of Regional Haze Submittal 

B. Reasonable Progress Goals (RPGs) Development 

B.1.Calculations of Baseline Visibility Conditions: ((40 CFR 51.308(d)(2)(i))

The period for establishing baseline visibility conditions is 2000 to 2004. For each 

mandatory Class I Federal area located within the state, the state must determine the 

average degree of visibility impairment (expressed in deciviews) for the most impaired 

and least impaired days (i.e. the 20 percent most impaired days and 20 percent least 

impaired days) for each of these years. Baseline conditions are the average of these 

annual values. For each mandatory Class I Federal area located within the state, the plan 

needs to calculate the number of deciviews by which baseline conditions exceed natural 

visibility conditions for the most impaired and least impaired days. Where onsite 

monitoring is not available the baseline visibility conditions must be established using the 

most representative monitoring available for the 2000-2004 period in consultation with 

US EPA. 

State Regional Haze Submittal 

Page 12 

Baseline visibility conditions at each Tennessee Class I area are estimated using 

sampling data collected at the IMPROVE monitoring site at one of the two Class I areas 

in Tennessee. A five year average (2000 to 2004) was calculated for each of the 20 

percent worst and 20 percent best visibility days in accordance with 40 CFR 51.308(d)(2) 

and Guidance for Tracking Progress Under the Regional Haze Rule, EPA-454-03-004, 

September 2003. IMPROVE data records for Great Smoky Mountains for the period 

2000 to 2004 meet the USEPA requirements for data completeness (75 percent for the 

year and 50 percent for each quarter). IMPROVE does not operate a monitor at Joyce 

Kilmer Wilderness and considers the IMPROVE monitor at Great Smoky Mountains to be 

representative of visibility in the Joyce Kilmer area. The light extinction and deciview 

visibility values for the 20 percent worst and 20 percent best visibility days at the Class I 

areas are based on data and calculations included in Appendix B of this SIP. 

Table 2.3-1 Natural Background and Baseline Conditions for Tennessee Class I 

Areas

Baseline Visibility Conditions 2000-2004 

Class 1 area 

Average for 

20 percent 

Worst Days 

(deciviews) 

Average for 

20 percent 

Best Days 

(deciviews)

Bext (Mm-1) 

Average for 

20 percent 

Worst Days

Bext (Mm-1) 

Average for 

20 percent 

Best Days

Great Smoky Mountains 30.3 13.6 216.3 40.2 

Joyce Kilmer Wilderness 30.3 13.6 216.3 40.2 

EPA Findings: Tennessee has appropriately addressed this provision. In cases where 

onsite monitoring is not available, 40 CFR 51.308(d)(2)(i) requires states to use the most 

representative monitoring available for the 2000-2004 period to establish baseline 

visibility conditions, in consultation with US EPA. EPA concurs with the use of data 
8 

from the IMPROVE monitor at Great Smoky Mountains National Park for the Joyce 

Kilmer-Slickrock Wilderness Area because Great Smoky Mountains Park is the nearest 

Class I area and in fact, these two areas are contiguous to one another, and the areas 

possess similar characteristics, such as meteorology and topography. 
9 

III. Evaluation of State Regional Haze Submittal 

B. Reasonable Progress Goals (RPGs) Development 

B.2. Calculations of Natural Visibility Conditions: ((40 CFR 51.308(d)(2)(iii)) 

For each mandatory Class I Federal area located within the State, natural visibility 

conditions must be calculated by estimating the degree of visibility impairment existing 

under natural conditions for the most impaired and least impaired days, based on 

available monitoring information and appropriate data analysis techniques as specified in 

EPA-454/B-03-005, Guidance for Estimating Natural Visibility Conditions Under the 

Regional Haze Program or an approved alternative technique.

State Regional Haze Submittal 

Pages 10-11 

Natural background visibility, as defined in Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Program, EPA-454/B-03-005, September 2003, is 

based on annual average concentrations of fine particle components. The same annual 

average natural background visibility is assumed for all Class I areas in the eastern 

United States (separate values are estimated for the western United States). Natural 

background visibility for the 20 percent worst days is estimated by assuming that fine 

particle concentrations for natural background are normally distributed and the 90th

percentile of the annual distribution represents natural background visibility on the 20 

percent worst days (i.e, Method 1 prediction per EPA default estimate guidance). For 

detailed information on the 20 percent worst days and 20 percent best days for TN Class 

I areas for the baseline year 2002, please refer to Appendix F-2. 

In the 2003 guidance, USEPA also provided that states may use a “refined approach” to 

estimate the values that characterize the natural visibility conditions of the Class I areas. 

The purpose of such a refinement would be to provide more accurate estimates with 

changes to the extinction algorithm that may include the concentration values, factors to 

calculate extinction from a measured particular species and particle size, the extinction 

coefficients for certain compounds, geographical variation (by altitude) of a fixed value, 

and the addition of visibility pollutants. 

In 2005 the IMPROVE Steering Committee made recommendations for a refined 

equation that modifies the terms of the original equation to account for the most recent 

data. The choice between use of the old or the new equation for calculating the visibility 

metrics for each Class I area is made by the state in which the Class I area is located. 

The VISTAS states chose to use the new IMPROVE equation as the basis for the 

conceptual description because it takes into account the most recent review of the science 

and because it is recommended by the IMPROVE Steering Committee. For more detailed 

discussion of the two IMPROVE equations, see Appendix B. 
10 

Table 2.3-1 Natural Background and Baseline Conditions for Tennessee Class I 

Areas

Class 1 area Average for 

20% Worst 

Days 

(deciviews) 

Average for 

20% Best 

Days 

(deciviews) 

Average for 

20% Worst 

Days 

Bext (Mm-1) 

Average for 

20% Best 

Days 

Bext (Mm-1) 

Great Smoky 

Mountains

11.1 4.5 30.8 15.8 

Joyce KilmerSlickrock11.1 4.5 30.8 15.8 

EPA Findings: EPA required the State of Tennessee to submit a request to the EPA 

Regional Administrator requesting approval for the use of the VISTAS methodology for the 

new IMPROVE equation for its Class I areas. A September 13, 2007, letter justifying the 

need for this approach was sent and approval from the Regional Administrator was 

provided to the State on October 5, 2007. North Carolina and Tennessee are sharing the 

lead in setting goals for the Great Smoky Mountains Class I area and North Carolina has the 

lead for setting goals for the Joyce Kilmer – Slickrock Class I area. Tennessee has 

appropriately addressed this provision. 

 
11 

III. Evaluation of State Regional Haze Submittal 

B. Reasonable Progress Goals (RPGs) Development 

B.3. Uniform Rate of Progress (UROP or “Glidepath”) for Reasonable Progress: 

(40 CFR 51.308(d)(1) and (40 CFR 51.308(d)(1)(i)(B)) 

For each mandatory Class I Federal area located within the state, the state must establish 

goals (expressed in deciviews) that provide for reasonable progress towards achieving 

natural visibility conditions. For each Class I area within the state, the state must analyze 

and determine the rate of progress needed to attain natural visibility conditions by the 

year 2064 and determine the uniform rate of visibility improvement (measured in 

deciviews) that would need to be maintained during each implementation period in order 

to attain natural visibility conditions by 2064. The state must show that the RPG for each 

mandatory Class I Federal area represents at least as much visibility improvement as is 

expected to result from implementation of other requirements of the CAA during the 

applicable planning period. (40 CFR 51.308(d)(1)(vi)) The RPGs must provide for an 

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

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

over the same period. Modeling is not used to determine RPGs and does not determine 

whether reasonable progress has been met. Modeling is one part of the reasonable 

progress analysis. The modeling results are used to determine if future year visibility at 

Class I areas are estimated to be on a (glide) path towards reaching natural background. 

State Regional Haze Submittal 

Pages 86-88 

The Regional Haze Rule at 40 CFR section 51.308(d)(1) requires States to establish 

reasonable progress goals for each Class I area within the state (expressed in deciviews) that 

provide for reasonable progress towards achieving natural visibility. In addition, USEPA 

released guidance on June 7, 2007 to use in setting reasonable progress goals. 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 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 reasonable progress goal. 

In accordance with the requirements of 40 CFR §51.308(d)(1), this Regional Haze SIP 

establishes reasonable progress goals for each Class I area in Tennessee. To calculate the 

rate of progress represented by each reasonable progress goal, TDEC-APC compared 

baseline visibility conditions to natural visibility conditions in each 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. 

Table 8.0-1. Tennessee 2018 Reasonable Progress Goals (in deciviews) 
12 

Class I Area Baseline 

Visibility 

for 20% 

Worst 

Days 

Reasonable 

Progress Goal 

– 20% Worst 

Days 

(Improvement)

Baseline 

Visibility 

For 20% 

Best Days 

Reasonable 

Progress Goal 

20% Best Days

(Improvement)

Great Smoky 

Mountains 

National Park 

30.28 23.50 

(6.78) 

13.58 12.11 

Joyce KilmerSlickrock 

Wilderness 

30.28 23.50 

(6.78) 

13.58 12.11 

Pages 17-18, 51 

The following are glidepaths for the 20 percent most impaired days for Great Smoky 

Mountains National Park and Joyce Kilmer-Slickrock Wilderness Area, assuming 

uniform rate of progress toward regional haze goals. Natural background visibility at 

both sites is predicted to be between 11 and 12 dv. Natural background visibility 

calculations are based on EPA’s default natural conditions estimates (Method 1) as 

explained in Appendix B-4 (page 31). 

(Method 1 Prediction = Default Calculation per EPA guidance) 

Uniform Rate of Reasonable Progress Glide Path

Great Smoky Mountains - W20% Data Days

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

20

00

20

04

20

08

20

12

20

16

20

20

20

24

20

28

20

32

20

36

20

40

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44

20

48

20

52

20

56

20

60

20

64

Year

Haziness Index (Deciviews)

Glide Path Natural Condition (Worst Days) Observation Method 1 Prediction
13 

 

 (Method 1 Prediction = Default Calculation per EPA guidance) 

Uniform Rate of Progress Glidepath for 20 percent worst days at Great Smoky Mountains 

National Park and Joyce Kilmer Wilderness Area. 

Figure 7.2.4-3 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. 

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

20

00

20

04

20

08

20

12

20

16

20

20

20

24

20

28

20

32

20

36

20

40

20

44

20

48

20

52

20

56

20

60

20

64

Year

Baseline Natural Condition (20% Best Days) Observation Method 1 Prediction

Uniform Rate of Reasonable Progress Glide Path

Joyce Kilmer-Slickrock - W20% Data Days

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

20

00

20

04

20

08

20

12

20

16

20

20

20

24

20

28

20

32

20

36

20

40

20

44

20

48

20

52

20

56

20

60

20

64

Year

Haziness Index (Deciviews)

Glide Path Natural Condition (Worst Days) Observation Method 1 Prediction
14 

Appendix G, Pages G-5 – G-10 

2 Reasonable Progress Goals 

For each Class I area, there are three metrics of visibility that are part of the 

determination of reasonable progress: 

1) Natural conditions, 

2) Baseline conditions 

3) Current conditions. 

Each of the three metrics includes the concentration data of the visibility impairing 

pollutants as different terms in the light extinction algorithm, with respective extinction 

coefficients and relative humidity factors. Total light extinction is then converted to 

deciviews, and an average value for both the 20 percent best and 20 percent worst 

visibility days is calculated. 

After the natural, baseline, and current conditions are calculated, a uniform rate of 

progress, or glidepath, can be created for the 20% worst days for each Class I area. 

Next, an analysis of potential control measures is performed to determine what level of 

control would be achievable in the given timeframe and what the potential improvement 

to visibility would be as a result of these controls. After the potential control analysis, 

reasonable progress goals for the Class I areas are determined after consultation with 

surrounding states. The entire RPG determination for Tennessee Class I areas is 

described in Appendix H. 

3 Model Application 

The purpose of a modeling assessment of uniform rate of progress is to determine if a 

proposed control strategy will result in uniform rate of progress being met when 

measured concentrations of particulate matter are used to estimate visibility impairment 

at some future date. The modeling is applied in a relative sense, similar to the fine 

particulate matter (PM25) attainment test. The following sections outline the process to 

determine 2018 projections from regional modeling, as suggested in the “Guidance on 

the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality 

Goals for Ozone, PM2.5, and Regional Haze”(from this point forward, referred to as 

“Attainment Guidance”). 

3.1 Determination of 20% Best and Worst Days 

The first step in developing model projections is to rank visibility (in deciviews) on each 

day with observed speciated PM2.5 data for each of the 5 years comprising the base 

period (2000-2004) for each Class I area. Day-specific observations for mass associated 

with sulfate (SO4), nitrates (NO3), organic carbon (OC), elemental carbon (EC), soil, and 

coarse matter (CM), should be used to calculate bext for each day using climatological 

relative humidity adjustment factor(s) (f(rh)). Total light extinction (bext)for all 

components should be converted to deciviews for each day to get a daily deciview value. 
15 

3.2 Determine Baseline Conditions 

The ranked visibility days from the first step are then used to calculate the average 

baseline deciviews for the 20% best and worst days. First, the mean deciview value for 

the identified 20% worst- and best visibility days in each year is calculated (dvcurrent). 

The 5 year mean deciview values reflecting mean visibility on the days with best visibility 

and then averaged to determine the baseline values for the best days, or the dvbaseline

values. Then the 5 year mean deciview values reflecting worst visibility are averaged 

together. This represents the value subject to improvement to meet the glidepath for 

regional haze. 

For each of the Tennessee Class I areas, the baseline visibility conditions were estimated 

using sampling data collected at Interagency Monitoring of Protected Visual 

Environments (IMPROVE) monitoring sites at one of the two Class I areas in Tennessee. 

A five year average (2000 to 2004) was calculated for each of the 20 percent worst and 

20 percent best visibility days in accordance with 40 CFR 51.308(d)(2) and the USEPA’s 

Guidance for Tracking Progress Under the Regional Haze Rule. IMPROVE data records 

for Great Smoky Mountains for the period 2000 to 2004 meet the USEPA’s requirements 

for data completeness (75 percent for the year and 50 percent for each quarter). 

IMPROVE does not operate a monitor at Joyce Kilmer Wilderness Area and considers 

the IMPROVE monitor at Great Smoky Mountains to be representative of visibility in the 

Joyce Kilmer Wilderness Area. The light extinction and deciview visibility values for the 

20 percent worst and 20 percent best visibility days at the Class I areas are based on 

data and calculations included in Appendix B of this SIP. Table 3.2-1 summarizes the 

mean yearly visibility conditions and the baseline visibility conditions for Tennessee 

Class I areas on both the 20% best and 20% worst days. 

Table 3.2-1: Baseline Visibility Conditions and Natural Conditions for the Tennessee 

Class I areas. 

dvbaseline Natural Condtions dvbaseline Natural Condtions

Great Smoky Mountains 

National Park (GSMNP) 30.28 11.05 13.58 4.54

Joyce Kilmer (JOKI) 30.28 11.05 13.58 4.54

 

 

Worst Visiblity Days Best Visiblity Days Site

 

3.3 Relative Response Factor Calculation 

The next step is to use base year and future year modeling results to estimate a relative 

response factor (RRF) for each component of PM2.5 on the 20% best and worst 

monitoring days. Simply put, the RRF is the average future year concentration near the 

monitor divided by the average base year concentration or: 

Average Modeled Base Year Concentration 

Average Modeled Future Year Concentration RRF =
16 

To accomplish this step, concentration for each component of PM2.5 and coarse matter 

(the difference between particles less than 10 micrometers in diameter (PM10) and PM2.5) 

are extracted from the base year and future year modeling output near IMPROVE 

monitoring sites for the monitored best and worst days. The component concentrations 

are then averaged to develop base and future year average component concentrations. 

The future year average component concentrations are then divided by their respective 

base year component concentrations to develop RRFs for each component of PM2.5 and 

coarse matter. 

For a numerical example, consider Table 3.3-1, which has all the pertinent data for the 

GSMNP1 IMPROVE monitor. Looking at the top table, the first column identifies the 

20% best days identified in step 1 (Section 3.1). The next six columns have the 12km 

modeled base year (2002) concentration values near the monitor corresponding to the 

20% best days. The next six columns have the 12km modeled future year (2018) 

component concentrations near the monitor for the same set of days. The final six 

columns contain the daily RRF values for each component species, which is simply the 

future concentration divided by the base year concentration. The bottom row of the table 

contains the average values for the base year components, the future year components, 

and the RRFs for each of the average component values. The bottom table contains the 

same data for the 20% worst days. 
17 

Table 3.3-1: Base year concentrations, future year concentrations, and RRF for Great 

Smoky Mountain National Park (GSMNP1) on the monitored 20% best days (top) and 

20% worst days (bottom), based on 12km modeling results. 

20% Best Days at 

GSMNP1

Julian Date SO4 NO3 OC EC SOIL CM SO4 NO3 OC EC SOIL CM SO4 NO3 OC EC SOIL CM

8 1.732 0.444 1.453 0.247 1.102 0.771 1.706 0.685 1.391 0.172 1.293 0.844 0.985 1.543 0.958 0.697 1.173 1.095

11 1.090 1.050 1.780 0.415 2.115 1.279 0.945 1.169 1.794 0.264 2.446 1.547 0.867 1.113 1.008 0.635 1.156 1.209

14 2.091 0.377 3.074 0.353 1.583 0.489 1.743 0.364 2.899 0.263 1.602 0.495 0.834 0.966 0.943 0.744 1.012 1.014

23 3.095 0.002 0.632 0.070 0.223 0.249 1.164 0.000 0.571 0.050 0.256 0.278 0.376 0.000 0.903 0.713 1.146 1.116

32 2.654 0.778 1.378 0.229 1.293 0.482 1.968 0.724 1.349 0.154 1.309 0.533 0.742 0.931 0.979 0.674 1.012 1.105

38 0.523 0.430 0.575 0.101 0.416 0.307 0.344 0.426 0.547 0.058 0.448 0.386 0.658 0.991 0.951 0.577 1.076 1.255

50 1.178 0.041 2.334 0.271 0.791 0.294 0.820 0.026 2.172 0.217 0.905 0.348 0.696 0.620 0.930 0.799 1.144 1.182

59 1.555 0.073 0.890 0.142 0.903 0.508 1.502 0.130 0.843 0.102 0.934 0.508 0.966 1.789 0.947 0.720 1.034 1.000

62 2.530 2.313 1.043 0.173 0.959 0.247 2.926 2.091 1.048 0.127 1.030 0.266 1.156 0.904 1.004 0.735 1.075 1.075

68 2.013 0.156 1.256 0.184 0.396 0.527 1.116 0.125 1.235 0.166 0.425 0.552 0.554 0.804 0.983 0.902 1.071 1.046

89 0.571 0.450 1.074 0.116 0.713 0.294 0.508 0.301 1.029 0.092 0.728 0.351 0.888 0.668 0.958 0.792 1.022 1.192

116 1.319 0.211 1.964 0.238 1.297 1.176 0.914 0.072 1.848 0.157 1.446 1.297 0.693 0.340 0.941 0.660 1.115 1.103

194 1.990 0.005 2.088 0.145 0.360 0.387 1.000 0.019 1.807 0.112 0.498 0.433 0.503 3.632 0.865 0.774 1.383 1.120

257 2.486 0.000 0.861 0.045 0.182 0.201 0.899 0.000 0.760 0.028 0.213 0.228 0.362 3.286 0.883 0.625 1.171 1.137

269 0.423 0.042 0.633 0.059 0.368 0.282 0.257 0.018 0.618 0.033 0.391 0.352 0.608 0.434 0.976 0.567 1.063 1.247

299 5.879 0.658 3.823 0.278 1.602 0.846 3.330 1.063 3.643 0.172 1.841 0.972 0.566 1.617 0.953 0.619 1.149 1.150

302 3.034 0.000 0.718 0.047 0.182 0.222 1.321 0.000 0.659 0.032 0.198 0.255 0.435 0.000 0.917 0.688 1.088 1.146

308 1.052 0.851 1.769 0.325 1.746 1.036 0.887 0.675 1.830 0.208 1.906 1.297 0.843 0.794 1.034 0.639 1.092 1.252

320 1.250 0.376 1.079 0.221 1.290 0.508 0.700 0.644 1.135 0.161 1.356 0.631 0.560 1.712 1.052 0.727 1.051 1.243

326 1.696 2.036 1.200 0.289 1.966 0.840 1.860 1.934 1.187 0.176 2.306 0.966 1.097 0.950 0.990 0.611 1.173 1.151

341 1.745 3.191 3.016 0.609 4.148 1.241 1.732 3.831 2.941 0.394 4.458 1.433 0.992 1.201 0.975 0.647 1.075 1.155

347 0.705 0.071 0.883 0.130 0.768 0.292 0.452 0.241 0.811 0.079 0.773 0.356 0.641 3.405 0.918 0.607 1.006 1.219

356 1.903 0.823 2.267 0.267 1.610 0.941 1.796 0.696 2.181 0.190 1.473 0.909 0.944 0.845 0.962 0.712 0.915 0.966

Mean 

Concentration 1.848 0.625 1.556 0.215 1.131 0.583 1.300 0.662 1.491 0.148 1.228 0.662 0.703 1.060 0.958 0.688 1.085 1.136

Base Year Future Year RRFs

20% Worst Days 

at GSMNP1

Julian Date SO4 NO3 OC EC SOIL CM SO4 NO3 OC EC SOIL CM SO4 NO3 OC EC SOIL CM

56 4.456 0.154 5.656 0.605 1.734 0.399 2.398 0.348 5.021 0.474 1.957 0.482 0.538 2.253 0.888 0.784 1.128 1.210

122 2.416 0.002 3.134 0.321 0.291 0.474 1.710 0.005 3.054 0.303 0.332 0.494 0.708 2.034 0.975 0.944 1.144 1.043

128 7.068 0.000 3.328 0.192 0.529 0.606 3.117 0.001 2.942 0.145 0.688 0.687 0.441 0.000 0.884 0.757 1.302 1.132

137 5.661 0.003 2.704 0.173 0.636 0.636 2.653 0.003 2.479 0.115 0.805 0.688 0.469 1.101 0.917 0.664 1.265 1.082

152 8.223 0.000 5.054 0.212 1.075 0.665 3.632 0.014 4.470 0.130 1.311 0.771 0.442 0.000 0.884 0.614 1.220 1.159

164 3.700 0.009 6.481 0.186 0.857 0.842 1.562 0.008 5.831 0.120 1.050 1.002 0.422 0.900 0.900 0.644 1.225 1.190

170 5.701 0.000 3.934 0.160 0.762 0.506 2.988 0.002 3.610 0.096 0.948 0.565 0.524 0.000 0.918 0.602 1.245 1.117

173 4.181 0.002 2.586 0.155 0.497 0.497 2.045 0.003 2.291 0.106 0.632 0.539 0.489 1.284 0.886 0.686 1.270 1.083

182 8.517 0.000 5.780 0.232 1.174 0.887 4.106 0.001 5.141 0.147 1.460 1.033 0.482 0.000 0.890 0.634 1.244 1.165

188 5.631 0.000 3.792 0.173 0.615 0.301 2.433 0.001 3.323 0.125 0.835 0.333 0.432 5.389 0.876 0.720 1.359 1.108

191 5.882 0.000 4.062 0.215 0.731 0.649 2.722 0.003 3.551 0.161 0.886 0.740 0.463 0.000 0.874 0.750 1.212 1.140

197 11.592 0.001 4.508 0.243 1.258 0.899 3.622 0.004 3.822 0.137 1.453 1.102 0.312 4.958 0.848 0.566 1.155 1.226

203 5.851 0.000 4.326 0.132 0.475 0.472 2.566 0.001 3.909 0.088 0.619 0.532 0.439 0.000 0.904 0.669 1.304 1.128

212 8.142 0.009 3.423 0.237 1.506 1.070 5.302 0.006 2.957 0.149 1.639 1.206 0.651 0.681 0.864 0.630 1.088 1.127

215 4.647 0.000 4.268 0.202 0.622 0.405 1.832 0.001 3.774 0.137 0.781 0.452 0.394 0.000 0.884 0.679 1.256 1.115

218 7.146 0.000 5.856 0.309 1.515 0.777 2.675 0.004 5.290 0.213 1.842 0.901 0.374 0.000 0.903 0.689 1.216 1.160

221 5.120 0.004 6.957 0.378 1.030 0.597 1.890 0.004 6.373 0.275 1.380 0.721 0.369 1.021 0.916 0.726 1.340 1.208

224 9.523 0.000 10.352 0.511 1.313 0.657 3.163 0.014 9.558 0.422 1.678 0.799 0.332 0.000 0.923 0.825 1.278 1.215

227 6.679 0.000 3.450 0.164 0.438 0.518 2.243 0.002 2.929 0.117 0.580 0.630 0.336 0.000 0.849 0.713 1.325 1.217

233 2.498 0.000 4.201 0.262 0.798 0.777 1.280 0.001 3.732 0.211 0.931 0.933 0.513 4.739 0.888 0.804 1.168 1.200

248 4.788 0.000 4.428 0.223 1.359 0.835 2.454 0.012 3.802 0.131 1.565 0.951 0.512 53.000 0.858 0.587 1.152 1.139

251 7.636 0.000 5.041 0.254 1.101 0.332 3.318 0.011 4.551 0.165 1.499 0.378 0.434 88.583 0.903 0.651 1.362 1.137

254 12.383 0.000 8.373 0.443 2.635 1.371 5.267 0.038 7.808 0.267 3.047 1.581 0.425 0.000 0.933 0.603 1.157 1.153

260 15.114 0.001 5.427 0.206 1.334 1.012 7.367 0.005 4.721 0.118 1.398 1.102 0.487 7.116 0.870 0.570 1.048 1.089

Mean 

Concentration 6.874 0.001 4.846 0.243 0.980 0.686 3.041 0.006 4.344 0.169 1.190 0.789 0.442 4.571 0.896 0.695 1.213 1.149

Base Year Future Year RRFs
18 

3.4. Future Year Daily Concentration Calculation 

The fourth step in using model output to estimate the future visibility impairment is to 

multiply the relative response factors (determined in the previous step, Section 3.3) by the 

measured species concentration data during the base period (for the measured 20% best 

and worst days). This results in daily future year species concentrations data. 

This is similar to the final step in the ozone attainment test, where base year 

concentrations, or the current year design value (DVC) is multiplied by the RRF to 

determine the future design value (i.e. DVF = RRF * DVC). For regional haze, this 

calculation is performed for each best and worst day for the five-year base line period 

(calculated in step 2, Section 3.2) using an RRF for each PM component, for both the 

best days and the worst days. This produces future concentration estimates for SO4, NO3, 

OC, EC, Soil and CM, for each of the “worst” and “best” visibility days. 

3.5. Future Year Daily bext Calculation 

Once future year concentrations are calculated (Section 3.4) the future daily extinction 

coefficients are then calculated for the 20% best and 20% worst visibility days in each of 

the five base years. This is achieved by applying the new IMPROVE equation (see 

Appendix B for a more information on the new IMPROVE equation): 

bext ≈ 2.2 * fs(RH) * [Small Sulfate] + 4.8 * fL(RH) * [Large Sulfate] 

+ 2.4 * fs(RH) * [Small Nitrate] + 5.1 * fL(RH) * [Large Nitrate] 

+ 2.8 * {Small Organic Mass] + 6.1 * [Large Organic Mass] 

+ 10 * [Elemental Carbon] 

+ 1 * [Fine Soil] 

+ 1.7 * fss(RH) * [Sea Salt] 

+ 0.6 * [Coarse Mass] 

+ Rayleigh Scattering (site specific) 

+ 0.33 * [NO2 (ppb)] 

Model estimated daily concentrations are used with the corresponding base line daily 

relative humidity adjustment factor(s) (f(rh)) identified in step 1 (Section 3.1). 

3.6. Future Mean Deciview Values Calculation 

The final step is to calculate daily deciview values from the total daily extinction 

calculated in the previous step, and then compute the future average mean deciviews for 

the worst and best days for each year. The 5 years are then averaged together to get the 

final future mean deciview value for the worst and best days. 

The first step in this process is to convert the total daily bext for each day (calculated in 

the previous step, Section 3.5) to deciviews. This future year daily deciview value for 

each of the best and worst days is then averaged to determine the future deciview value 
19 

for the “worst” and “best” visibility days for each year. This leads to 5 future estimated 

mean deciview values for the “worst” and 5 future estimated mean deciview values for 

the “best” visibility days. The five yearly values for the best and worst days are then 

averaged to produce the final future mean deciview value, or dvfuture. Table 3.6-1 

displays the yearly daily deciview value for each year in the baseline period for both the 

20% worst days (center column) and the 20% best days (right column). The last row in 

the table displays the final future mean deciview value, or dvfuture. 

Table 3.6-1: Final future mean deciview values (dvfuture) and Natural Conditions for 

the Tennessee Class I areas, based on 12km modeling results. 

 

dvfuture Natural Condtions dvfuture Natural Condtions

Great Smoky Mountains 

National Park (GSMNP) 23.50 11.05 12.11 4.54

Joyce Kilmer (JOKI) 23.50 11.05 12.11 4.54

 8

 

Site Worst Visiblity Days Best Visiblity Days

The resulting dvfuture values for the “worst” and “best” visibility days can be compared 

to the dvbaseline values calculated in step 2 (Section 3.2). If the resulting change in 

deciviews is a negative number (future - base), this represents an improvement in 

visibility. Table 3.6-2 summarizes these calculation for the IMPROVE monitors 

associated with Tennessee Class I areas. From the table, it is apparent that the two 

Tennessee Class I areas are showing visibility improvement on both the 20% best and 

20% worst days. 

Table 3.6-2: Comparison of future deciview projections for 2018 compared to 2002 

baseline deciview estimates. 

Site DVbase DVfuture DVdiff DVbase DVfuture DVdiff

Great Smoky Mountains 

National Park (GSMNP) 30.28 23.50 -6.78 13.58 12.11 -1.47

Joyce Kilmer (JOKI) 30.28 23.50 -6.78 13.58 12.11 -1.47

 

 

20% Worst Days 20 % Best Days

EPA Findings: Tennessee has adequately addressed this provision. 
20 

III. Evaluation of State Regional Haze Submittal 

C. Long-Term Strategy 

C.1. Technical Basis for Strategy (40 CFR 51.308(d)(3)(iii)) 

The plan must document the technical basis, including modeling, monitoring and 

emissions information, on which the State is relying to analyze regional haze. The State 

may meet this requirement by relying on technical analyses developed by the regional 

planning organization and approved by all State participants

State Regional Haze Submittal 

The following is taken and/or summarized from Appendix H – RPG Evaluation and LTS 

4-4-08 (page H-3) 

EPA Note: The RHR requires states to establish RPGs for visibility improvement at each 

affected Class I area covering each approximately 10-year period until 2064. The State’s 

first set of RPGs will comprise a long term strategy (LTS) covering the period from the 

present until 2018. Appendix H provides an overview of this first LTS. 

Tennessee’s LTS contains the following components: 

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

regulations by 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. (See also EPA TSD Section 

III.B.3)

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. (See also EPA TSD Section III.C.3)

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

determinations for specific sources. 

VII. Identification of BART-eligible sources. (See also EPA TSD Section III.D.1) 

VIII. BART exemption modeling for BART-eligible sources. (See also EPA TSD 

Section III.D.2) 

IX. BART determinations for sources subject to BART. (See also EPA TSD Section 

III.D.3) 

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

reasonable progress control determinations. 
21 

XI. Determination of RPGs based on the visibility improvement expected by 2018. 

From SIP Narrative starting at page 25

Modeling Demonstration 

Modeling for regional haze was performed by VISTAS for the ten southeastern states, 

including Tennessee. The sections below outline the methods and inputs used by VISTAS 

for the regional modeling. Additional details are provided in Appendices C, D and M. 

The modeling analysis is a complex technical evaluation that begins by selection of the 

modeling system. VISTAS decided to use the following modeling system: 

• Meteorological Model: The Pennsylvania State University/National Center for 

Atmospheric Research (PSU/NCAR) Mesoscale Meteorological Model (MM5) is 

a nonhydrostatic, prognostic meteorological model routinely used for urban- and 

regional-scale photochemical, fine particulate matter, and regional haze 

regulatory modeling studies. A coarse 36-km horizontal grid domain covering the 

continental United States was used as the grid domain for MM5. 

• Emissions Model: The Sparse Matrix Operator Kernel Emissions (SMOKE) 

modeling system is an emissions modeling system that generates hourly gridded 

speciated emission inputs of mobile, nonroad mobile, area, point, fire and 

biogenic emission sources for photochemical grid models. 

• Air Quality Model: USEPA’s Models-3/ Community Multiscale Air Quality 

(CMAQ) modeling system is an ‘One-Atmosphere’ photochemical grid model 

capable of addressing ozone, particulate matter (PM), visibility and acid 

deposition at regional scale. For the VISTAS modeling, a coarse 36-km grid 

resolution was used for modeling the entire United States and a finer 12-km grid 

was used to model the eastern United States. The CMAQ model was run in the 

one-way nested grid mode. This allowed the larger outer domains to feed 

concentration data to the inner nested domain. 

Figure 5.4.1-1 shows the MM5 horizontal domain as the outer most, blue grid with the 

CMAQ 36-km domain nested in the MM5 domain. Figure 5.4.1-2 shows the 12-km grid, 

modeling domain for the VISTAS region. 
22 

Figure 5.4.1-1. The MM5 horizontal domain is the outer most, blue grid, with the 

CMAQ 36-km domain nested in the MM5 domain. 

 

Figure 5.4.1-2. A more detailed view of the 12-km grid over the VISTAS region. 

Care was taken in the selection of the modeling system used to develop the long-term 

strategy. The VISTAS states tried to ensure that the models selected were scientifically 

appropriate for the intended application and be freely accessible to all stakeholders. 

Scientifically appropriate means that the models address important physical and 

chemical phenomena in sufficient detail, using peer-reviewed methods. Freely accessible 

means that model formulations and coding are freely available for review and that the 

models are available to stakeholders, and their consultants, for execution and 

verification at no or low cost. These criteria were used in selecting the modeling system 

are documented on pages 26-30 of the SIP Narrative. 
23 

The entire year for 2002 was selected by VISTAS as the modeling year for this 

demonstration. (See pages 30-32) Meteorological inputs were developed for 2002 using 

the MM5 meteorological model. Configurations for the modeling MM5 and CMAQ 

modeling domains are summarized and discussed on pages 32-31, additional details are 

provided in the appendices) Emission inventories were also developed for 2002 and 

processed through the emissions model. These inputs were used in the air quality model 

to predict fine particle mass and visibility. The model results for 2002 were compared 

with observed meteorological and air quality data to evaluate model performance. 

Several configurations of the meteorological and air quality model were evaluated to 

select a configuration that gave the best overall performance for the VISTAS region. 

Emissions Controls Modeled (pages 43-47 SIP Narrative) 

There are significant control programs being implemented between the baseline period 

and 2018. These programs are described in more detail below. 

Federal and State Control Requirements 

CAIR . CAIR will permanently cap emissions of SO2 and NOx from EGUs in the eastern 

United States by 2015. When fully implemented, CAIR will reduce SO2 emissions from 

EGUs in these states by more than 70 percent, and NOx emissions by more than 60 

percent, from 2003 levels. For TVA, the electric utility that operates coal-fired EGUs in 

Tennessee, the following tables reflect the reductions expected: 

Emissions are aggregated at the facility level, rather than the unit level, as presented in 

the VISTAS emission inventories. 

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. 

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 
24 

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. 

TVA 

Facility Existing SO2 Controls (2006) Projected SO2 Controls** 

Allen 

None. Plant burns low-sulfur 

fuel. 2006 emission rate was 

0.62 lb/mmBtu SO2. 

None planned prior to 2015. 

Bull Run None 

Wet Scrubber. Completion 

projected in 2009. 

Cumberland Wet Scrubber No additional controls planned. 

Gallatin 

None. Plant burns low-sulfur 

fuel.2006 emission rate was0.63 

lb/mmBtu SO2.

None planned prior to 2015. 

John Sevier None 

Scrubber. Completion projected 

in 2012. 

Johnsonville None 

 Testing is underway to determine 

the viability of reducing SO2

emissions from 1.5 lb/mmBtu to 

0.9 lb/mmBtu by 2015, based on 

combustion of lower sulfur coal. 

Kingston None 

Wet scrubber. Completion 

projected in 2010. 

** Phase II CAIR requirements will require additional SO2 reductions within the TVA 

system by installing additional controls or by repowering or shutting down units.

NOx SIP Call. Phase I of the NOx SIP call applies to certain EGUs and large nonEGUs, including large industrial boilers and turbines, and cement kilns. Those states 

affected by the NOx SIP call in the VISTAS region have developed rules for the control of 

NOx emissions that have been approved by the USEPA. The NOx SIP Call has resulted 

in a 66 percent reduction in summertime NOx emissions from large stationary 

combustion sources in Tennessee. For this analysis, we capped the emissions for NOx 

SIP call-affected sources at 2007 levels, and carried forward the capped levels for the 

2009 and 2018 future year inventories. 

North Carolina CSA. Under the act, enacted in 2002, coal-fired power plants in North 

Carolina must achieve a 77-percent cut in NOx emissions by 2009 and a 73-percent cut 

in SO2 emissions by 2013. This legislation establishes annual caps on both SO2 and 

NOx emissions for the two primary utility companies in North Carolina, Duke Energy 

and Progress Energy. These reductions must be made in North Carolina, and 

allowances cannot be sold. 
25 

Georgia Multipollutant Bill. Georgia enacted regulations in summer 2007 to require 

coal fired power plants in Georgia to reduce SO2 by approximately 90%, NOx by 

approximately 50%, and mercury by an estimated 75-85% by 2015. Reductions will 

affect 21 units at seven facilities. The rule requires specific controls on specific units 

according to a specific schedule. This is not a cap and trade rule, thus there are no 

allowances to be banked, sold or traded. 

Consent Agreements. Under a settlement agreement, by 2008, Tampa Electric will install 

permanent emissions-control equipment to meet stringent pollution limits; implement a 

series of interim pollution-reduction measures to reduce emissions while the permanent 

controls are 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. agreed to spend $1.2 billion by 2013 to eliminate 

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

generating plants in Virginia and West Virginia. 

AEP [US District Court for the Southern District of Ohio, Eastern Division]: In October 

2007 American Electric Power agreed to spend $4.6 billion dollars to eliminate 72,000 

tons of NOx emissions each year by 2016 and 174,000 tons of SO2 emissions each year 

by 2018 from sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, 

Virginia and West Virginia. 

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

rates by 61 percent 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. 

One-hour ozone SIPs (Atlanta / Birmingham / Northern Kentucky). New SIPs have been 

submitted to the USEPA to demonstrate attainment of the one-hour ozone National 

Ambient Air Quality Standard (NAAQS). These SIPs require NOx reductions from 

specific coal fired power plants and address transportation plans in these cities. 

NOx RACT in 8-hour Nonattainment Area SIPs. North Carolina’s SIP for the Charlotte 

/ Rock Hill / Gastonia nonattainment area includes Reasonable Achievable Control 

Technology (RACT) for NOx for two facilities located in the nonattainment area: Philip 

Morris USA and Norandal USA. These controls were also modeled in 2018. Additional 

RACT controls may be realized as other companies subject to RACT complete the 

determination, but RACT-level controls were assumed for just these two sources. 

Heavy Duty Diesel (2007) Engine Standard (for on-road trucks and buses). USEPA set 

a PM emissions standard for new heavy-duty engines of 0.01 grams per brakehorsepower-hour (g/bhp-hr), to take full effect for diesel engines in the 2007 model year. 

This rule 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
26 

be lowered to enable modern pollution-control technology to be effective on these trucks 

and buses. USEPA 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 (On-road vehicles). USEPA mobile rules include the Tier 2 fleet 

averaging program, modeled after the California 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. Tier 2 standards became effective in the 2005 model year. 

Large Spark Ignition and Recreational Vehicle Rule. USEPA has adopted new 

standards for emissions of oxides of nitrogen (NOx), hydrocarbons (HC), and carbon 

monoxide (CO) from several groups of previously unregulated nonroad engines. 

Included in these are large industrial spark-ignition engines and recreational vehicles. 

Nonroad spark-ignition engines are those powered by gasoline, liquid propane gas, or 

compressed natural gas rated over 19 kilowatts (kW) (25 horsepower). These engines 

are used in commercial and industrial applications, including forklifts, electric 

generators, airport baggage transport vehicles, and a variety of farm and construction 

applications. Nonroad recreational vehicles include snowmobiles, off-highway 

motorcycles, and all-terrain-vehicles. These rules were initially effective in 2004 and 

will be fully phased-in by 2012. 

Nonroad Diesel Rule. This rule sets standards that will reduce emissions by more than 

90 percent from nonroad diesel equipment, and reduce sulfur levels by 99 percent from 

current levels in nonroad diesel fuel starting in 2007. This step will apply to most 

nonroad diesel fuel in 2010 and to fuel used in locomotives and marine vessels in 2012. 

Industrial Boiler/Process Heater/RICE MACTs. The USEPA issued final rules to 

substantially reduce emissions of toxic air pollutants from industrial, commercial and 

institutional boilers, process heaters and from stationary reciprocating internal 

combustion engines (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 SO2 and PM in conjunction with the toxic air 

pollutant reductions. The applied Maximum Achievable Control Technology (MACT) 

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

USEPA’s industrial boiler MACT rules were vacated on June 8, 2007. The VISTAS 

states decided to leave these controls in the modeling since it is believed that by 2018, 

the USEPA will have re-promulgated a boiler MACT rule or states will have addressed 

the issue through state rule making. Note: Tennessee provided a justification for 

relying on this rule even with the vacature. It was sent as a clarification to the Regional 

Haze SIP via email on July 9, 2008. 

Combustion Turbine MACT. The projection inventories do not include the NOx cobenefit effects of the MACT regulations for Gas Turbines or stationary Reciprocating
27 

Internal Combustion Engines, which USEPA estimates to be small compared to the 

overall inventory. 

VOC 2-, 4-, 7-, and 10-year MACT Standards. Various point source MACTs and 

associated emission reductions were implemented. Reductions occurring before 2002 

were assumed to be accounted for in the 2002 base year inventory. 

Sources and Pollutants relied on for LTS (pages 57-59 SIP Narrative) 

An important step toward identifying further reasonable progress measures is to identify 

the key pollutants contributing to visibility impairment at each Class I area. To 

understand the relative benefit of further reducing emissions from different pollutants, 

source sectors, and geographic areas, VISTAS engaged the Georgia Institute of 

Technology to perform emission sensitivity model runs using CMAQ. Emissions in 2009 

were reduced by 30 percent for each pollutant sensitivity run. The pollutant 

contributions that were evaluated were: 

• SO2 from EGU sources in each VISTAS state, other RPOs in the VISTAS 12 km 

grid, and Boundary Conditions from outside the 12 km domain. 

• SO2 from non-EGU point sources in each VISTAS state, other RPOs, and 

Boundary Conditions 

• NOx from ground level sources (on-road plus off-road plus area) in each VISTAS 

state and other RPOs. In the VISTAS states, these reductions were only applied 

to specific counties that were of concern for 8-hour ozone nonattainment. 

• NOx from point (EGU plus non-EGU) sources in each VISTAS state and other 

RPOs 

• NH3 from all sources in VISTAS and other RPOs 

• Volatile Organic Compounds from anthropogenic and biogenic sources in the 12 

km modeling domain 

• Primary Carbon from all ground level sources in each VISTAS state and other 

RPOs. In the VISTAS states, these reductions were only applied to specific 

counties that were of concern for PM2.5 nonattainment. 

• Primary Carbon from all point sources in each VISTAS state and other RPOs 

• Primary Carbon from all fires in each VISTAS state and other RPOs 

Figure 7.4-1 below shows the average of the 20 percent worst visibility days for Great 

Smoky Mountains National Park. Responses for 20 percent worst days were calculated 

by averaging the responses of the 20 percent worst days that were modeled in the two 

episodes. These results were used to understand the relative importance of pollutant 

contributions at this site. 
28 

Figure 7.4-1. CMAQ projections of visibility responses on 20 percent worst days at 

Great Smoky Mountains to 30 percent reductions from a 2009 inventory for 

visibility-reducing pollutants in different source categories and geographic areas. 

As Figure 7.4-1 illustrates the greatest visibility benefits on the 20 percent worst days for 

the Great Smoky Mountains National Park are projected to result from further reducing 

SO2 from EGUs. Benefits are projected from SO2 reductions from EGUs in several 

VISTAS states including Alabama, Georgia, Kentucky, North Carolina, South Carolina, 

Tennessee, Virginia, and West Virginia. Contributions from other RPOs and from the 

boundary conditions are comparatively small and the greatest benefits would likely be 

from further EGU reductions within the VISTAS states. Additional, smaller benefits are 

projected from additional SO2 emission reductions from non-utility, industrial point 

sources. The pattern of relative SO2 contributions from non-EGUs among the various 

VISTAS states is similar to the pattern of relative SO2 contributions from EGUs. 

TDEC-APC concludes that reducing SO2 emissions from EGU and non-EGU point 

sources in the VISTAS states would have the greatest visibility benefits for the Tennessee 

Class I areas. Contributions from the Midwest RPO and MANE-VU are greater at the 

Class I areas bordering these RPOs. Contributions from outside the VISTAS 12-km 

modeling domain are more important for the coastal Class I areas. 

MODEL PERFORMANCE EVALUATION (see pages 33-41 of SIP Narrative) 

The initial modeling effort focused on evaluating previous regional air quality modeling 

applications and testing candidate model configurations for the SMOKE emissions and 

CMAQ model for the VISTAS 36-km and 12-km modeling domains. This effort resulted

Great Smoky Mtns, TN (20% Worst Days)

-12.00

-10.00

-8.00

-6.00

-4.00

-2.00

0.00

SO2_EGU

SO2_

nonEGU

NOx_Ground

NOx_Point

NH3

VOCs

PC_Ground

PC_Point

PC_Fires

∆

Bext (Mm-1)

Bio VOC.

Anthro VOC

BCs

MRPO

M-VU

CEN

VISTAS

WV

VA

TN

SC

NC

MS

KY

GA

FL

AL

Great Smoky Mtns, TN (20% Worst Days)

-12.00

-10.00

-8.00

-6.00

-4.00

-2.00

0.00

SO2_EGU

SO2_

nonEGU

NOx_Ground

NOx_Point

NH3

VOCs

PC_Ground

PC_Point

PC_Fires

∆

Bext (Mm-1)

Bio VOC.

Anthro VOC

BCs

MRPO

M-VU

CEN

VISTAS

WV

VA

TN

SC

NC

MS

KY

GA

FL

AL
29 

in a report recommending the model configuration for the annual emissions and air 

quality modeling, which is included as part of the VISTAS Emissions and Air Quality 

Modeling Protocol. (See Appendix C) The evaluation of the meteorological modeling 

configuration can be found in Appendix F.1, with a summary of the final meteorological 

and air quality modeling configuration in the modeling protocol contained in Appendix E 

and Appendix C, respectively. 

Air quality model performance for the 2002 modeling year was initially tested in 2004 

using an early version of the VISTAS emissions inventory. In keeping with the oneatmosphere objective of the CMAQ modeling platform, model performance was 

evaluated based on measured ozone, fine particles, and acid deposition in the Air Quality 

System (AQS), IMPROVE, Speciated Trends Network (STN), Southeastern Aerosol 

Research and Characterization (SEARCH), National Acid Deposition Program (NADP) 

and Clean Air Status and Trends Network (CASTNet) monitoring networks 

The air quality model’s performance was evaluated with respect to individual 

components of fine particulate matter (PM2.5), as good model performance of the 

component species will dictate good model performance of total or reconstituted fine 

particulate matter. Model performance of the total fine particulate matter and the 

resulting total light extinction was also provided as a means to discuss the overall model 

performance for the SIP. 

The soccer and bugle plots for the all of the VISTAS IMPROVE monitors are included 

here for summary purposes. The goal and criteria levels used for regional haze model 

performance were 30% and 60%, respectively, for mean fractional bias and 50% and 

75%, respectively, for mean fractional error. Plots were presented for the average 

monthly concentrations and the performance statistics for all of the most significant light 

scattering component species (Sulfate, Nitrate, and Organic Carbon) for the 20% best 

days and 20% worst days. Plots for individual IMPROVE monitors associated with 

Tennessee Class I areas are included in Appendix F.2. 

The soccer plots of monthly concentrations (Figures. 6.2-1 and 6.2-2) show that values 

for nitrate generally fall outside of criteria performance thresholds (red box). Sulfates 

and organic carbon generally fall within goal thresholds (green box), with a couple of 

months falling just outside the goal thresholds but well within the criteria thresholds. In 

these figures, each point represents a month. Figure 6.2-3 contains separate soccer plots 

for each season. The seasonal plots emphasize poorer nitrate performance in the 

summer (does not even appear on the plots provided because performance is off scale 

with other constituents), when observed nitrate is quite low and predicted nitrate is even 

lower. When concentration is factored into performance criteria, nitrate performance 

improves with respect to mean fractional bias and mean fractional error (Figures 6.2-4 

and 6.2-5) 

Additionally, performance assessed at the “one atmosphere” level was also deemed 

acceptable for ozone and particulate matter at various monitoring sites (STN, FRM, 

CASTNet, etc.). Overall, VISTAS found the Base G2 modeling results to be 
30 

representative and acceptable for use in modeling projection for ozone, particulate 

matter, and regional haze. 

All Sites CMAQ 12km - 2002 Monthly

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

160.0

180.0

200.0

-180.0 -120.0 -60.0 0.0 60.0 120.0 180.0

Fractional Bias

Mean Fractional Error 

Sulfate

Nitrate

Organics

Criteria

Goal

Figure 6.2-1: Soccer plot depicting both the mean fractional error and fractional bias for 

component concentration for all VISTAS sites. 

All Sites CMAQ 12km - 2002 Monthly

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

-75.0 -25.0 25.0 75.0

Fractional Bias

Mean Fractional Error 

Sulfate

Nitrate

Organics

Criteria

Goal

Figure 6.2-2: A zoomed view of the soccer plot depicting both the mean fractional error 

and fractional bias for component concentration for all VISTAS sites. 

VISTAS IMPROVE Ga2a 12km - 2002 Spring (Apr May Jun) 

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

-75.0 -25.0 25.0 75.0

Fractional Bias

Fractional Error 

Sulfate

Nitrate

Ammon.

Organics

EC

Soils

PM25

PM10

CM

Criteria

Goal

VISTAS IMPROVE Ga2a 12km - 2002 Summer (Jul Aug Sep) 

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

-75.0 -25.0 25.0 75.0

Fractional Bias

Fractional Error 

Sulfate

Nitrate

Ammon.

Organics

EC

Soils

PM25

PM10

CM

Criteria

Goal
31 

Figure 6.2-3: Seasonal soccer plots for all VISTAS IMPROVE monitors.

All Sites CMAQ 12km - 2002 Monthly

0.0

50.0

100.0

150.0

200.0

0.0 1.0 2.0 3.0 4.0 5.0 6.0

Average Concentration (μg/m3)

Mean Fractional Error 

Sulfate

Nitrate

Organics

Criteria

Goal

Figure 6.2-4: Bugle plot of the mean fraction bias for particulate matter and its component 

concentrations for all VISTAS sites. 

VISTAS IMPROVE Ga2a 12km - 2002 Fall (Oct Nov Dec) 

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

-75.0 -25.0 25.0 75.0

Fractional Bias

Fractional Error 

Sulfate

Nitrate

Ammon.

Organics

EC

Soils

PM25

PM10

CM

Criteria

Goal

VISTAS IMPROVE Ga2a 12km - 2002 Winter (Jan Feb Mar) 

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

-75.0 -25.0 25.0 75.0

Fractional Bias

Fractional Error 

Sulfate

Nitrate

Ammon.

Organics

EC

Soils

PM25

PM10

CM

Criteria

Goal
32 

All Sites CMAQ 12km - 2002 Monthly

-200.0

-150.0

-100.0

-50.0

0.0

50.0

100.0

150.0

200.0

0.0 1.0 2.0 3.0 4.0 5.0 6.0

Average Concentration (μg/m3)

Mean Fractional Bias 

Sulfate

Nitrate

Organics

(+) Criteria

(+) Goal

(-) Goal

(-) Criteria

Figure 6.2-5: Bugle plot of mean fraction error for particulate matter and its component 

species for all VISTAS sites. 

Tennessee Class 1 Areas Performance 

The following section provides stack bar charts comparing observed fine particulate 

matter composition and modeled fine particulate matter composition. The charts have 

been split into two charts, with the first displaying the 20% best days followed by the 

chart for the 20% worst days. Stacked bar charts have been developed for the IMPROVE 

monitoring site located in the Great Smoky Mountains National Park (GSMNP1). (See 

Figure 1.4-1). The Great Smoky Mountains National Park IMPROVE monitor is used to 

represent the Joyce Kilmer-Slickrock Wilderness Area. 

The stacked bar chart allows a side-by-side comparison of the each day’s observed and 

modeled compositional and total light extinction. Within each bar the color codes are: 

• Yellow = light extinction due to sulfates (bextSO4) 

• Red = light extinction due to nitrates (bextNO3) 

• Green = light extinction due to organic carbon (bextOC) 

• Black = light extinction due to elemental (bextEC) 

• Brown = light extinction due to soil (bextSoil) 

• Grey = light extinction due to coarse mass (bextCM) 

The components are presented in the same order for both the observed (left hand bar) 

and modeled bar (right hand bar), so it easy to identify days when the prediction light 

extinction for the component differs from the observed. The total height of the bar 

provides the total reconstructed particulate matter light extinction value. Note the 

differences in scale of the two charts; on the 20% best days modeled extinction is 

generally less than 20 Mm-1 different from measured values. For 20% worst days total
33 

differences between modeled and measured extinction varies from near zero to greater 

than 200 Mm-1. 

A cursory view of the stacked bars charts reiterates that sulfates are a large contributor 

to light extinction in the Great Smoky Mountains National Park on both 20% best days 

and 20% worst days. The bar charts also suggest that organic carbon and nitrates are 

important on the 20% best days. The bar charts for the 20% best days reiterate the 

general under prediction seen in previous sections. The under prediction of sulfate on 

most of the 20% best days appears to be the crux of the under prediction, with the under 

prediction of nitrate observed on some days. On most 20% best days there is a small 

under prediction of SO4 and on some 20% best days there is a large nitrate under 

prediction. 

Comparing the 20% best day charts to the 20% worst days charts, one notices that the 

various components of particle pollution play a more prominent role in the 20% best 

days than with the 20% worst days. Also, the species make up on the 20% best days 

varies more widely compared to the 20% worst days. This suggests accurately modeling 

each species is especially important on the 20% best days. 

With the bar chart for the 20% worst days, it can be seen that model performance does 

improve across the sites. Light extinction due to sulfate prediction is better, but still falls 

short on some days. Light extinction due to organic carbon also becomes more 

important to total light extinction. Much like the sulfate component, the organic carbon 

component accuracy has improved performance over the 20% best day series, though 

some days are still under predicted. Overall, TDEC-APC found model performance to 

fall within acceptable limits for model performance. TDEC-APC further asserts the one 

atmosphere modeling performed by the VISTAS contractors is representative of 

conditions in the southeastern states and is applicable for use in setting reasonable 

progress goals for the Class I areas. 
34 

6.3.1 Great Smoky Mountain National Park 

Best 20% Obs (left) vs 2002gt2a (right) at GRSM1

0

10

20

30

40

50

60

70

80

90

100

8 11 14 23 32 38 50 59 62 68 89 116 194 257 269 299 302 308 320 326 341 347 356

Julian Date

bext (1/Mm)

bextCM

bextSOIL

bextEC

bextOC

bextNO3

bextSO4

Worst 20% Obs (left) vs 2002gt2a (right) at GRSM1

0

50

100

150

200

250

300

350

400

56 122 128 137 152 164 170 173 182 188 191 197 203 212 215 218 221 224 227 233 248 251 254 260

Julian Date

bext (1/Mm)

bextCM

bextSOIL

bextEC

bextOC

bextNO3

bextSO4

Figure 6.3-1: Stacked bar chart for GSMNP1 on the 20% best days (top) and 20% 

worst days (bottom). Observed composition is presented in the left hand bar, with 

modeled composition represented by the right hand bar. 
35 

Once model performance was deemed adequate, the current and future year emissions 

were processed through the emissions model. The air quality modeling results are used 

to determine a relative reduction in future visibility impairment, which is used to 

determine reasonable progress. 

More detailed discussions of the modeling protocol, quality assurance report, 

procedures, models and data used in the regional haze analysis can be found in 

Appendices C, E, F and G. The archival and acquisition of data and modeling input 

and output files are discussed in Appendix I. 

EPA Findings – The technical analyses and modeling to assess uniform rate of progress 

and to support the LTS were successfully developed consistent with EPA’s interim and 

final modeling guidance. EPA accepts the VISTAS technical modeling to support the 

LTS and determine visibility improvement for uniform rate of progress because the 

modeling system was chosen and simulated according to EPA modeling guidance. EPA 

agrees with the VISTAS model performance procedures and results, and that the CMAQ 

is an appropriate tool for the regional haze assessments for the Tennessee LTS and 

Regional Haze SIP. 

However, CAIR is an element of Tennessee’s LTS. Tennessee is subject to 

EPA’s CAIR, and has rules addressing the CAIR requirements adopted into its SIP (72 

FR 46388 (August 20, 2007 and 74 FR 61535 (November 25, 2009)). The State 

demonstrated that CAIR satisfies reasonable progress for SO2 for its EGUs for this first 

planning period. On July 11, 2008, the U.S. Court of Appeals for the District of 

Columbia Circuit issued its decision to vacate and remand both CAIR and the associated 

CAIR FIPs in their entirety. North Carolina v. EPA, 531 F.3d 836 (DC Cir. 2008). 

However, in response to EPA's petition for rehearing, the Court issued an order 

remanding CAIR to EPA without vacating either CAIR or the CAIR FIPs. North Carolina 

v. EPA, 550 F.3d 1176 (DC Cir. 2008). The Court thereby left CAIR in place in order to 

“temporarily preserve the environmental values covered by CAIR” until EPA replaces it 

with a rule consistent with the Court's opinion. Id. at 1178. The Court directed EPA to 

``remedy CAIR's flaws'' consistent with its July 11, 2008, opinion, but declined to impose 

a schedule on EPA for completing that action. Id. Although the DC Circuit Court found 

CAIR to be flawed, the rule was remanded without vacatur and thus remains in place. 

Thus, CAIR and the CAIR FIP are currently in effect in subject states, and EPA is 

continuing to approve CAIR provisions into SIPs as appropriate. 

Prior to the CAIR remand by the Court, EPA believed the State’s reliance on 

CAIR for the specific BART and reasonable progress provisions affecting its EGUs was 

adequate. The regional haze provisions specify that a state may not adopt a RPG that 

represents less visibility improvement than is expected to result from other CAA 

requirements during the planning period (40 CFR 51.308(d)(1)(vi)). As such, Tennessee 

took into account emission reductions anticipated from the CAIR in determining its 2018 

RPGs. Due to the need to address the remand of CAIR to EPA by the DC Circuit, states 

may not permanently rely upon the emissions reductions predicted by CAIR. For this 

reason, EPA cannot fully approve Regional Haze SIP revisions that rely on CAIR. 
36 

Also, on July 30, 2007, the U.S. District Court of Appeals mandated the vacatur 

and remand of the Industrial Boiler MACT Rule. Notwithstanding the vacatur of the this 

rule, the VISTAS states, including Tennessee, decided to leave these controls in the 

modeling for their regional haze SIPs since it is believed that by 2018, EPA will have repromulgated an industrial boiler MACT rule or the states will have addressed the issue 

through state-level case-by-case MACT reviews in accordance with section 112(j) of the 

CAA. EPA finds this approach acceptable for the following reasons. EPA proposed a 

new Industrial Boiler MACT rule to address the vacatur on June 4, 2010, (75 FR 32006), 

and issued a final rule on March 21, 2011, (76 FR 15608), giving Tennessee time to 

assure the required controls are in place prior to the end of the first implementation 

period in 2018. In the absence of an established MACT rule for boilers and process 

heaters, the statutory language in section 112(j) of the CAA specifies a schedule for the 

incorporation of enforceable MACT-equivalent limits into the title V operating permits of 

affected sources. Should circumstances warrant the need to implement section 112(j) of 

the CAA for industrial boilers, EPA would expect, in this case, that compliance with 

case-by-case MACT limits for industrial boilers would occur no later than January 2015, 

which is well before the 2018 RPGs for regional haze. In addition, the RHR requires that 

any resulting differences between emissions projections and actual emissions reductions 

that may occur will be addressed during the five-year review prior to the next 2018 

regional haze SIP. The expected reductions due to the original, vacated Industrial Boiler 

MACT rule were relatively small compared to the State's total SO2, PM2.5, and coarse 

particulate matter (PM10) emissions in 2018 (i.e., 0.5 to 1.5 percent, depending on the 

pollutant, of the projected 2018 SO2, PM2.5, and PM10 inventory), and not likely to affect 

any of Tennessee's modeling conclusions. Thus, if there is a need to address 

discrepancies such that projected emissions reductions from the now-vacated Industrial 

Boiler MACT were greater than actual reductions achieved by the replacement MACT, 

EPA would not expect that this would affect the adequacy of the existing Tennessee 

regional haze SIP. 

References used in the EPA review: 

1. EPA’s Guidance on the Use of Models and Other Analyses for Demonstrating 

Attainment of Air Quality Goals for Ozone, PM2.5, and Regional Haze. Located at 

http://www.epa.gov/scram001/guidance/guide/final-03-pm-rh-guidance.pdf (EPA454/B-07-002), April 2007. 

2. U.S. EPA, (2001), “(Draft) Guidance for Demonstrating Attainment of Air Quality 

Goals for PM2.5 and Regional Haze”, http://www.epa.gov/ttn/scram/guidance_sip.htm 

3. 2002 Base Year Emission Inventory SIP Planning: 8-hr Ozpne, PM2.5 and Regional 

Haze US EPA memorandum from Lydia Wegman to Peter Tsirigotis, November 18, 

2002. 

4. July 9, 2008 email from Travis Blake to Brenda Johnson. Subject: R: question about 

MACT reductions. 
37 

5. Clean Air Act (CAA) §§112(j)(2), (3), (5), and (6). 

6. CAA §505 specifies procedures for notification to the Administrator and affected 

States.
38 

III. Evaluation of State Regional Haze Submittal 

C. Long-Term Strategy 

C.2. Identification of Sources and Factors to be Considered for Reasonable 

Progress: (40 CFR 51.308(d)(3)(iv-v)) 

The State must identify all anthropogenic sources of visibility impairment considered by 

the State in developing its long-term strategy. The State should consider major and minor 

stationary sources, mobile sources, and area sources. The State must consider, at a 

minimum, the following factors in developing its long-term strategy: (A) emission 

reductions due to ongoing air pollution control programs, including measures to address 

reasonably attributable visibility impairment; (B) Measures to mitigate the impacts of 

construction activities; (C) Emissions limitations and schedules for compliance to achieve 

the reasonable progress goal; (D) source retirement and replacement schedules; (E) 

smoke management techniques for agricultural and forestry management purposes 

including plans as currently exist within the State for these purposes; measures to 

mitigate the impacts of construction activities; (F) enforceability of emission limitations 

and control measures; and the (G) anticipated net effect on visibility due to projected 

changes in point, area, and mobile source emissions over the period. 

State Regional Haze Submittal 

Pages 81-83 

The following summarizes the process for determining reasonable progress for Tennessee 

sources. For a detailed discussion of the reasonable progress assessments for all units 

contribution greater than one percent to any Class I area in Tennessee or in neighboring 

states, please see Appendix H. 

Step 1: Determine pollutants of concern. 

VISTAS evaluated the species contribution on the 20 percent worst visibility days and 

concluded that sulfate accounted for greater than 70 percent 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. 

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 percent 

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 EGUs. 

TDEC-APC evaluated the amount of SO2 reduction from the EGU sector based upon 

consultations with TVA. The EGUs in Tennessee are expected to reduce their SO2 emissions 
39 

by approximately 75% between 2002 and 2018. TVA reduced significant (~58% from the 

1994 to 2002 time period) SO2 emission tonnage prior to that under Phase I acid rain 

reductions as a part of the Title IV Program for an overall 2018 reduction of >85%. TDECAPC believes it has an accurate understanding of where emission reductions will occur in 

the Tennessee EGU sector based upon fixed installations of post combustion FGD controls. 

We have concluded that at this time that CAIR constitutes reasonable measures for 

Tennessee EGUs during this first assessment period (between baseline and 2018). While 

reasonable progress applies to existing sources, TDEC-APC will follow the visibility analysis 

requirements as required in the federal NSR/PSD rules as part of all new major source 

NSR/PSD permitting actions. These rules appear in Chapter 1200-3-9 and are periodically 

updated to conform to federal requirements. Because these rules are periodically updated, 

TDEC-APC declares that this statement is simply a recitation of the rules and not an 

inclusion of the current version of the rule into the Tennessee Regional Haze SIP. 

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 

Area of Influence for a given Class I area and identified those emission units with a 

contribution of one percent or more to the visibility impairment at that Class I area. A list of 

sources considered in the reasonable progress evaluation can be found in Section 5.0 of 

Appendix H in the area of influence discussion. Some sources had greater than one percent 

impacts, but TDEC-APC did not request a four-factor analysis from the source due to 

information already in the possession of the agency. A brief description of these sources is 

as follows: 

• Intertrade Holdings in Polk County – The majority of the source is being dismantled 

and being shipped out of the country. The remaining operations have very little 

sulfur dioxide emissions. 

• TVA’s Bull Run Fossil Plant in Anderson County is being fitted out with a new flue 

gas desulfurization unit that should be operational in 2009. 

• 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 (1,145 tons) are not reflected in the VISTAS 

inventory for 2018. Because the predicted 2018 future visibility levels were well 

below the glide slopes for the uniform rate of progress for nearby Class I areas, and 

the modeled 2018 emissions from Tate & Lyle were significantly overstated, TDECAPC determined that no further analysis was required at this facility for this review 

period. As predicted visibility levels are replaced with future measured visibility 

levels, a reassessment of the facility’s SO2 emissions in light of those measured 

visibility levels can be conducted. 
40 

• Aluminum Company of America (ALCOA) in Blount County was a BART source for 

its sulfur dioxide emissions and under review in that program 

• Eastman Chemical Company in Sullivan County was a BART source installing 

significant emission control technology to reduce its sulfur dioxide emissions 

• APAC-TN Harrison Construction Company in Blount County was erroneously 

modeled by VISTAS as a ready mix concrete plant with a 2018 future projected 

source emission strength of 200 tons per year of SO2. At this level, there was a 

resulting 3.9 percent impact at the Great Smoky Mountains National Park. In 

actuality, the facility is an asphalt drum mix plant with a current SO2 allowable of 

20.3 TPY. For illustration purposes only, if this value were doubled to a 2018 

emission rate of 40 TPY, the predicted impact would be 0.0077 percent, well 

below the impact evaluation level of one percent. For these reasons, no further 

attempts were made to evaluate the facility under the four-factor analysis. 

• 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. 

• TVA’s Cumberland Fossil Plant already has flue gas desulfurization units and it is 

also a BART source. 

Great Smokies - Point Source SO2 Contribution to TN Class I Areas 
41 

 Joyce Kilmer-Slickrock - Point Source SO2 Contribution to TN Class I Areas 

Step 5: Evaluate the four factors. 

Each emission unit identified in Step 4 above is being 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. 

Pages 85-86 

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 2.4 and demonstrated in Figures 2.4-1 and 2.4-2, 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 with the TN Division of Forestry to develop a 

smoke management program that addresses the issues laid out in USEPA’s 1998 draft 

guidance for smoke management plans. TDEC-APC will not make any smoke 

management plan a part of its SIP due to flexibility reasons. It would simply be too 
42 

cumbersome to formally revise the SIP for minor changes to a smoke management 

program or plan. Any resulting plan would simply be offered as additional assurances 

that the emission reductions in other source categories would “carry the day” in 

effectively solving regional haze issues. 

Also as discussed in Section 2.4 and demonstrated in Figures 2.4-1 and 2.4-2, fine soils 

are a relatively minor contributor to visibility impairment at the Class I areas in 

Tennessee. TDEC-APC has an effective relationship with the Tennessee Department of 

Transportation (TDOT) in working on air quality action days, diesel retrofits of 

construction equipment, distribution of alternative fuels and the innovative use of the 

Congestion Mitigation and Air Quality Improvement Program (CMAQ) money to 

improve air quality in nonattainment areas. TDEC-APC will engage TDOT in 

discussions to control road construction project dust emissions as part of its contract bid 

specifications. As with the above-described smoke management plan, TDEC-APC will 

not place this in the SIP nor rely upon it to reach an air quality or emission related 

target. Instead, it will be used as an assurance that the proven plan has more than 

adequate measures with these incidental measures present as an unrelied upon backup. 

In addition, TDEC-APC’s Rule 1200-3-8-.03 requires additional control measures on 

source operating permits to control dust emissions. That rule and the entire Chapter 

1200-3-8 for controlling fugitive dust may be seen at: 

http://tennessee.gov/sos/rules/1200/1200-03/1200-03-08.pdf . The citation of Rule 1200-

3-8-.03 is offered only for reference purposes. It is not offered for inclusion into the 

Tennessee Regional Haze SIP 

Note that benefits from the rule have not been included in the VISTAS modeling runs. 

Copies of Chapter 1200-3-8 rule are attached to Appendix H. 

In regard to agricultural ammonia, TDEC-APC will await the emission sampling and 

Best Management Practices arising from EPA’s CAFO Consent Order Agreements prior 

to initiating and control measures for agricultural ammonia. 

VISTAS is working on a modeling run that will include the cumulative benefits from the 

emission controls discussed in Section 7.2.1, any controls resulting from BART 

determinations within the VISTAS states and any controls resulting from the states within 

VISTAS to address reasonable progress. If the modeling runs and analyses are completed 

within a reasonable period of time prior to the final Regional Haze SIP submittal on 

December 17, 2007, TDEC-APC will incorporate these findings in the final SIP, 

including revising reasonable progress goals if needed. If the modeling runs and 

analyses are not completed in time, TDEC-APC will review the information as it becomes 

available and determine if a SIP revision is necessary. 

EPA Findings TDEC has concluded that, at this time, the application of BART 

constitutes reasonable progress for six units and thus, is not requiring any additional 

controls for reasonable progress. As discussed in EPA’s Reasonable Progress 

Guidance document, since the BART analysis is based, in part, on an 

assessment of many of the same factors that must be addressed in establishing 
43 

the RPG, EPA believes it is reasonable to conclude that any control requirements 

imposed in the BART determination also satisfy the RPG-related requirements 

for source review in the first RPG planning period.1

 Thus, EPA agrees with the 

State’s conclusions that the BART control evaluations satisfy reasonable 

progress for the first planning period for these six units. Prior to the CAIR remand 

by the Court, EPA believed the State’s demonstration that CAIR satisfies reasonable progress 

for SO2 for affected EGUs for the first planning period to be acceptable on the basis that the 

CAIR requirements reflect the most cost-effective controls that can be achieved over the 

CAIR SO2 compliance timeframe, which spans out to 2015. However, as explained in 

Section III.C.1–EPA Findings,, the State’s demonstration regarding CAIR and reasonable 

progress for EGUs, and other provisions in this SIP revision, are based on CAIR and thus, the 

Agency proposes to issue a limited approval and a proposed limited disapproval of the State’s 

regional haze SIP revision. 

 

1

 Pages 4.2-4.3, July 1, 2007 memorandum from William L. Wehrum, Acting Assistant 

Administrator for Air and Radiation, to EPA Regional Administrators, EPA Regions 1-

10, Guidance for Setting Reasonable Progress Goals under the Regional Haze Program, 
44 

III. Evaluation of State Regional Haze Submittal 

C. Long-Term Strategy 

C.3. Source or Source Category Specific Analyses for Reasonable Progress: (40 

CFR 51.308(d)(1)(i)(A) 

For the significant sources and source categories located within the State and determined 

to be significantly impacting a mandatory Class I Federal area, the state must document 

that it considered the costs of compliance, the time necessary for compliance, the energy 

and non-air quality environmental impacts of compliance, the remaining useful life of 

any potentially affected sources, and how these factors were taken into consideration in 

establishing the reasonable progress goal. 

State Regional Haze Submittal 

Pages 84-85 

Each emission ... is being 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. 

Results of the four-factor analysis: 

TDEC-APC determined that two non-EGU sources, Bowater Newsprint in Calhoun, 

Tennessee and INVISTA in Hixson, Tennessee should be subjected to the four-factor 

analysis because those facilities contributed one percent 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. These facility analyses appear in Appendix H.5. 

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

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 
45 

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. 

Pages H.58-H.63 

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 

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% 
46 

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 noncondensible 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 INVISTAHIXSON/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: 

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: 
47 

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 costeffectiveness 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. 

Table 6-6. INVISTA 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 
48 

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 costeffectiveness 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 
49 

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. 
50 

INVISTA

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 fuelswitching 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. 

 

EPA Findings: Tennessee has appropriately addressed this provision. TDEC concluded, 

based on their evaluation of these companies’ analyses, that no further controls were 

warranted. After reviewing TDEC’s methodology and analyses, EPA finds Tennessee’s 

conclusions acceptable. Regarding the fuel switching option evaluated for INVISTA, 

while the $1,225 /ton of SO2 is below the cost effectiveness threshold established by 

TDEC, the limited expected visibility improvement from reducing emissions 214 

tons/year is an acceptable basis to defer consideration of additional controls to the next 

assessment period. EPA also finds that all currently available control technologies at the 

time of analysis and applicable to these facilities were evaluated fully in terms of the four 

reasonable progress factors, and the State consistently applied its criteria for reasonable 

compliance costs, and where it differed, the State included justification for the other 

factors influencing the control determination. The State also appropriately documented 

in its SIP the technical analysis to assess the need and implementation of reasonable 

progress controls as applicable for those non-CAIR EGU emission units of SO2

emissions. This involved identification of existing controls on applicable emission units, 

potential control options for applicable emissions, and the successful application of the 

four factors to determine the feasibility of controls that constituted reasonable progress. 
51 

III. Evaluation of State Regional Haze Submittal 

C. Long-Term Strategy 

C.4. Enforceability of Reasonable Progress Measures: The plan needs to provide 

enforceable emissions limitations and schedules for compliance for each newly adopted 

measure needed to achieve the reasonable progress goals. 

State Regional Haze Submittal 

No newly adopted source specific measures were required to achieve the reasonable 

progress goals. 

EPA Findings: Tennessee has appropriately addressed this provision. 
52 

III. Evaluation of State Regional Haze Submittal 

D. Best Available Retrofit Technology (BART) Requirements

D.1 Identification of all BART Eligible Sources: The implementation plan should 

include a list of all BART-eligible sources within the State. 

State Regional Haze Submittal 

Starting at Page 50 of the SIP Narrative 

Section 169A of the CAA directs States to assess certain large, older emission 

sources for additional controls in order to address visibility impacts. States are directed 

to conduct BART determinations for such sources in specific source categories, and 

which contribute to visibility impairment in Class I areas. The 1999 regional haze rule 

includes the BART requirement, and directs States to include BART in their regional haze 

SIPs. On July 6, 2005, USEPA published a revised final rule, including Appendix Y to 40 

CFR Part 51, the Guidelines for BART Determinations Under the Regional Haze Rule 

(hereinafter referred to as the “BART Guidelines”) that provides direction to states on 

determining which of these sources should be subject to BART, and how to determine 

BART for each source. 

A BART-eligible source is one which has the potential to emit 250 tons or more of 

a visibility-impairing air pollutant, was put in place 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.’’ 

For those sources subject to BART, 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. 

Pages 60-61 

The following is a list of facilities with BART-eligible sources in Tennessee. TDEC-APC 

developed this list by examining the 2002 NEI data summary. The list was electronically 

sorted to retrieve sources that had emissions of visibility impairing pollutants that were 

greater than or equal to 250 tons per year. The pollutants included sulfur dioxide, 

nitrogen oxides, particulate matter, and volatile organic compounds as set forth in the 

proposed BART rule in the FR Vol. 69, No. 87, May 5, 2004 on page 25216. Per the final 

BART rule in the FR Vol. 70, No.128 on page 39112 and page 39160, the list was 

expanded to include ammonia. 
53 

Next, the sources of the aforementioned emission magnitude were examined by SIC code 

and NAICS code to determine if they fell under one of the BART 26 source categories. 

Most large VOC sources were excluded from BART because they were not in the BART 

specific source categories. Using this electronically reduced list, a file review and 

dialogue with the identified source was used to determine if the source construction date 

was in the 1962 to 1977 BART period. That final list was then evaluated under BART 

exemption modeling that is already discussed in the Regional Haze SIP that was taken 

out for public comment. See Appendix L for a detailed description of each BARTeligible emission unit: 

FACILITY NAME 

Aluminum Company of America (Alcoa) – South Plant 

DuPont White Pigment and Mineral Products (Humphreys County) 

Eastman Chemical Company – Tennessee Operations 

E I DuPont de Nemours and Company, Inc. (Old Hickory) 

E I DuPont de Nemours and Company, Inc. (Shelby County) 

Holston Army Ammunition Plant 

Intertrade Holdings, Inc. 

Liberty Fibers Corporation 

Lucite International 

Owens Corning 

Packaging Corporation of America (PCA) 

PCS Nitrogen 

Tennessee Valley Authority (TVA) – Bull Run Fossil Plant 

Tennessee Valley Authority (TVA) – Cumberland Fossil Plant 

Zinifex 

Weyerhaeuser Corporation (now Domtar Paper Company) - Sullivan County 

The BART-eligible sources were identified using the methodology in the BART 

Guidelines. 

• One or more emissions units at the facility fit within one of the 26 categories 

listed in the BART Guidelines2

;

 

2 List of BART Source Categories. The BART requirement only applies to sources in specific categories 

listed in the Clean Air Act. These categories are: (1) Fossil-fuel fired steam electric plants of more than 250 

million British thermal units (BTU) per hour heat input, (2) Coal cleaning plants (thermal dryers), (3) Kraft 

pulp mills, (4) Portland cement plants, (5) Primary zinc smelters, (6) Iron and steel mill plants, (7) Primary 

aluminum ore reduction plants, (8) Primary copper smelters, (9) Municipal incinerators capable of charging 

more than 250 tons of refuse per day, (10) Hydrofluoric, sulfuric, and nitric acid plants, (11) Petroleum 

refineries, (12) Lime plants, (13) Phosphate rock processing plants, (14) Coke oven batteries, (15) Sulfur 

recovery plants, (16) Carbon black plants (furnace process), (17) Primary lead smelters, (18) Fuel 

conversion plants, (19) Sintering plants, (20) Secondary metal production facilities, (21) Chemical process 

plants, (22) Fossil-fuel boilers of more than 250 million BTUs per hour heat input, (23) Petroleum storage 

and transfer facilities with a capacity exceeding 300,000 barrels, (24) Taconite ore processing facilities, 

(25) Glass fiber processing plants, and (26) Charcoal production facilities. 
54 

• The emission unit(s) were in existence on August 7, 1977 and began operation at 

some point on or after August 7, 1962; and 

• The limited potential emissions from all emission units identified in the previous 

two bullets emission units were greater than 250 tons or more per year of any of 

these visibility-impairing pollutants: SO2, NOx, and PM10. 

The BART Guidelines recommend addressing these visibility-impairing pollutants: SO2, 

NOx, and particulate matter, and suggest that States use their best judgment in 

determining whether to address VOC or ammonia emissions. TDEC-APC addressed SO2 

and NOx, and used particulate matter less than 10 microns in diameter (PM10) as an 

indicator for particulate matter to identify BART-eligible units, as the BART Guidelines 

recommend. As discussed in detail in Appendix L (BART related documentation 

narrative), VISTAS modeling demonstrated that VOCs and ammonia from point sources 

are not visibility-impairing pollutants. For this reason TDEC-APC did not evaluate 

emissions of VOCs. However, ammonia emissions were evaluated only from one major 

source of ammonia (i.e., PCS Nitrogen) in the BART determinations. 

EPA Findings: Tennessee has appropriately addressed this provision. 
55 

 

III. Evaluation of State Regional Haze Submittal 

D. Best Available Retrofit Technology (BART) Requirements

D2. Modeling or other Demonstrations for BART Exempt Sources: For each BARTeligible source in the State exempted from BART a demonstration, using an acceptable 

approach, that the source or group of sources does not violate the established threshold. 

The established exemption threshold for determining if a BART-eligible source 

contributes to regional haze cannot exceed 0.5 deciviews. 

State Regional Haze Submittal 

Pages 62-65 

Under the BART Guidelines, TDEC-APC may consider exempting some sources from 

BART if we find that they do not cause or contribute to visibility impairment in a Class I 

area. In accordance with the BART guidelines, TDEC-APC chose to perform sourcespecific analyses to determine which sources cause or contribute to visibility impairment 

using the CALPUFF model. The CALPUFF modeling protocol used for determining 

which facilities are subject to BART is included in Appendix L. 

TDEC-APC also examined the appropriateness of the 0.5 deciview threshold for potential 

“clusters” of BART sources that might be impacting a Class I area in a cumulative 

manner, and did not find evidence that an exemption threshold less than the 0.5 deciview 

threshold should be used. Appendix H’s main document describing reasonable progress 

has additional information in Section 5.0 regarding individual source impacts upon Class 

I areas. In accordance with the Guidelines, a contribution threshold of 0.5 deciviews 

was used for determining which sources were subject to BART. 

Tennessee initially identified sixteen (16) facilities with BART-eligible sources. Since the 

time that the BART-eligible sources were identified, Liberty Fibers Corporation has 

permanently shut down, and the BART-eligible boilers located at the facility have been 

dismantled. Additionally, Intertrade Holdings, Inc. has permanently shut down the acid 

plant that was determined to be BART-eligible (a reduction of sulfur dioxide of 

approximately 374 tons per year). Holston Army Ammunition Plant has requested a 

permit limit of 249 tons per year for the emissions units that make up their acid plant 

The Division of Air Pollution Control issued a federally enforceable permit restricting 

the acid plant emissions to 249 tons per year on February 25, 2008 (See Appendix L-12, 

pages 3-4). The subject acid plant consists of eight sources, with combined potential 

emissions of 638.2 tons of nitrogen oxides (NOx) before the issuance of the federally 

enforceable permit. However, this part of the facility has not been operated since 1997. 

The remaining sources with potential emissions above 250 TPY at this facility were either 

built before August 1962 or were built or modified after the promulgation of major NSR 

rules in 1977. The power boiler (#7) at the Weyerhaeuser facility (formerly Willamette 

Industries) in Sullivan county has been retired and the facility is no longer BART eligible. 

Appendix L-12 provides specific permit information on these BART exempted sources. 

The BART listing of the remaining twelve (12) operational sources is as follows and in 

Figure 3-1: 
56 

Aluminum Company of America (Alcoa) – South Plant 

DuPont White Pigment and Mineral Products (Humphreys County) 

Eastman Chemical Company – Tennessee Operations 

E I DuPont de Nemours and Company, Inc. (Old Hickory) 

E I DuPont de Nemours and Company, Inc. (Shelby County) 

Lucite International 

Owens Corning 

Packaging Corporation of America (PCA) 

PCS Nitrogen 

Tennessee Valley Authority (TVA) – Bull Run Fossil Plant 

Tennessee Valley Authority (TVA) – Cumberland Fossil Plant 

Zinifex 
57 

Figures from Appendix L 

 Figure 3-1 TN BART-Eligible Sources and Class I Areas. 

Eight (8) of Tennessee’s BART-eligible sources submitted exemption-modeling 

demonstrations. Results of these demonstrations are summarized in Tables 7.5.2-1 

through 7.5.2-2 below. Additional details are available in Appendix L. Facilities found 

to be subject to BART must complete a BART analysis (Table 7.5.2-3). 

Table 7.5.2-1 represents the six (6) facilities that were able to demonstrate exemption 

from BART based on CALPUFF modeling conducted using the VISTAS modeling 

protocol, VISTAS CALMET screening 12-km regional domain, and the old IMPROVE 

equation. No significant adverse comments were received during the public comment 

period. 

Table 7.5.2-1. BART Exemption Modeling Results for Sources using Old IMPROVE 

Equation – 12 Km. CALMET 

Facility Class 1 Areas Distance To 

Class I Area 

Impact 

(Change in 
58 

(km) dv) 

 DuPont – Humphreys County 

 (for SO2, NOx, and PM10) 

 Mammoth Cave NP 203 0.338 

 Mingo Wildlife Refuge 225 0.128 

 Sipsey Wilderness Area 200 0.369 

 DuPont – Shelby County 

 (for SO2, NOx and PM10) 

 Mingo Wildlife Refuge 218 0.151 

 Sipsey Wilderness Area 216 0.147 

 Lucite International 

 (for SO2, NOx, and PM10) 

 Mingo Wilderness Area 187 0.053 

 Sipsey Wilderness Area 253 0.040 

Owens Corning 

(for SO2, NOx,and PM10) 

Mammoth Cave NP 

 Mingo Wildlife Refuge 

 Sipsey Wilderness Area 

297 

187 

200 

0.045 

0.064 

0.040 

 PCS Nitrogen 

 (for SO2, NOx, NH3 and PM10) 

 Mingo Wildlife Refuge 186 0.166 

 Sipsey Wilderness Area 253 0.074 

 Zinifex – Clarksville 

 (for SO2, NOx, and PM10) 

 Cohutta Wilderness Area 312 0.099 

 Mammoth Cave NP 131 0.465 

 Mingo Wildlife Refuge 256 0.125 

 Sipsey Wilderness Area 247 0.237 

Table 7.5.2-2 represents the two (2) facilities that were able to demonstrate exemption 

from BART based on the VISTAS modeling protocol, VISTAS CALMET refined 4-km 

resolution (domain 3), and the old IMPROVE equation (PCA and TVA). 

Table 7.5.2-2. BART Exemption Modeling Results for Sources using Old IMPROVE 

Equation – 4 Km. CALMET 

Facility Class 1 Areas 

Distance To 

Class I Area 

(km) 

Impact 

(Change in 

dv) 

 TVA – Bull Run Fossil Plant 

 (for PM10) 

 Cohutta Wilderness Area 118 0.126 

 Great Smoky Mountains 

NP 48 0.445 

 Joyce Kilmer-Slickrock 

WA 63 0.226 

 Linville Gorge Wilderness 

Area 

200 0.063 

 Mammoth Cave National 

Park 209 0.033 

 Shinning Rock WA 131 0.081 

 Packaging Corp. of America 

 (for SO2, NOx and PM10 ) 

 Mammoth Cave National 

Park 299 0.101 
59 

 Mingo Wilderness Area 273 0.064 

 Sipsey Wilderness Area 100 0.247 

Table 7.5.2-3 represents the four (4) facilities that were not able to demonstrate 

exemption from BART based on the VISTAS modeling protocol. These sources are subject 

to the BART controls modeling demonstrations. 

Table 7.5.2-3. Modeling Determination Results for BART-Subject Sources 

Facility Class 1 Areas 

Distance To 

Class I Area 

(km) 

Impact 

(Change in 

dv) 

 Alcoa – South Plant (1) 

 (for SO2, NOx, and PM10) 

(New Improve Equation 

except MACA w/Old Improve 

Equation) 

 Cohutta Wilderness Area 

 Great Smoky Mountains 

Joyce Kilmer-Slickrock 

 Linville Gorge WA 

 Mammoth Cave NP (2)

 Shinning Rock WA 

99 

18 

16 

185 

244 

108 

0.335 

1.310 

0.686 

0.370 

0.350 

0.463 

 DuPonrt – Old Hickory 

 (for SO2, NOx and PM10) 

(New Improve Equation) 

 Mammoth Cave NP (3)

Cohutta Wilderness Area 

 Great Smoky Mountains 

 Joyce Kilmer-Slickrock 

 Sipsey Wilderness Area 

105 

233 

249 

254 

220 

0.504 

0.160 

0.220 

0.190 

0.310 

 Eastman Chemical (4) 

 (PM10 for SO2, NOx, and 

PM10)(New Improve 

Equation) 

 Cohutta Wilderness Area 

 Great Smoky Mountains 

 James River WA 

 Joyce Kilmer-Slickrock 

 Linville Gorge WA 

 Shinning Rock WA 

245 

98 

289 

174 

85 

124 

0.292 

0.992 

0.289 

0.470 

0.875 

0.543 

 TVA-Cumberland (5) 

 (for PM10) 

(Old Improve Equation) 

 Mammoth Cave NP 

 Mingo Wildlife Refuge 

 Sipsey Wilderness Area 

153 

233 

223 

1.359 

0.404 

0.557 

(1) Alcoa BART base case, refined 1-km runs, highest-1st to 8th-high value, 3% sulfur coal using New Improve Equation. 

(2) Alcoa exemption modeling, screening 4-km runs, 1st highest value, using Old Improve Equation only for MACA. 

(3) DuPont BART base case Mammoth Cave (MACA) modeling with New Improve Equation, refined 4-km runs, 8th highest value 

(occurs only 7 days in 2003 at 24 hour maximum firing rate). A maximum delta DV of 0.36 is obtained at only 3 days occurrence in 

2003 at monthly averaged maximum emission rate, which is more representative of the firing patterns for the Boilers. Revised summer 

time 24-hour maximum emission rates resulted in a 0.474 DV at MACA. This source is still subject to BART control assessment. 

 (4) Eastman BART control case, refined 4-km runs, 8th highest value, SDA/FF Controls, using New Improve Equation. 

(5) TVA-Cumberland BART base case, refined 4-km runs, 8th highest value, hydrated lime, using Old Improve Equation. 

Two of Tennessee’s BART-eligible sources are EGUs. These are TVA-Bull Run and TVACumberland Fossil Plants. These two sources have already installed or are installing 

scrubbers to reduce SO2 and Selective Catalytic Reduction (SCRs) to reduce NOx. 
60 

The USEPA has determined that, as a whole, the CAIR cap-and-trade program improves 

visibility more than implementing BART for individual sources in states affected by 

CAIR. A State that opts to participate in the CAIR program under 40 CFR 96.201-.224 

(Subpart AAA through EEE) need not require affected BART-eligible EGU to install, 

operate, and maintain BART for SO2 or NOx emissions. Given that all BART-eligible 

units are installing scrubbers and NOx controls, and since Tennessee is participating in 

CAIR and accepts USEPA’s overall finding that CAIR “substitutes” for BART for NOx 

and SO2, Tennessee’s EGUs were allowed to submit BART exemption modeling 

demonstrations for PM emissions only. TVA-Bull Run demonstrated that it does not 

contribute to visibility impairment in any Class I area. 

In total, eight (8) of Tennessee’s twelve (12) BART-eligible sources were able to 

demonstrate that they did not cause or contribute to visibility impairment in any Class I 

area within 300 km of the source. One source did exceed the threshold on only one Class 

I area out of four. Three sources used the refined 4-km CALMET resolution and one 

source used the new improve equation in efforts to demonstrate exemption. For further 

details about the BART exemption modeling, please refer to Appendix L. 

CALPUFF MODELING

TDEC-APC chose to perform source-specific analyses to determine which sources cause 

or contribute to visibility impairment using the CALPUFF model. The CALPUFF 

modeling protocol used for determining which facilities are subject to BART is included 

in Appendix L. TDEC-APC also examined the appropriateness of the 0.5 deciview 

threshold for potential “clusters” of BART sources that might be impacting a Class I 

area in a cumulative manner, and did not find evidence that an exemption threshold less 

than the 0.5 deciview threshold should be used. Appendix H’s main document describing 

reasonable progress has additional information in Section 5.0 regarding individual 

source impacts upon Class I areas. In accordance with the BART Guidelines, a 

contribution threshold of 0.5 deciviews was used for determining which sources were 

subject to BART. 

Determination of BART emissions to evaluate (from Appendix L) 

The guidelines required the States to 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. Tennessee used its best judgment and sensitivity 

modeling to determine that VOC and ammonia emissions did not have an impact on 

visibility in their Class I areas and state. The results show that the maximum impact from 

eliminating all point source VOC emissions in the VISTAS 12 km domain is less than a 

0.5 dv for all Class I areas in the VISTAS domain. Given that the fraction of the total 

point source VOC emissions that are also BART-eligible in the state of Tennessee is just 

8%2

, the expected impact of controlling VOCs from a BART source would be much less 

than the 0.5 dv threshold. VISTAS and the State of Tennessee conclude that VOCs from
61 

point sources are not a visibility impairing pollutant for BART purposes and that BARTeligible sources do not need to consider VOC emissions. 

Removal of the large NH3 emission sources results in minimal impact on visibility at 

Class I areas in the VISTAS region. At their discretion states may ask those few large 

sources to evaluate NH3 impacts and potential controls for NH3. Based on the CMAQ 

sensitivity analyses of the impact of ammonia emissions, the State determined that only 

one large TN source of ammonia emissions, PCS Nitrogen, would be required to evaluate 

those emissions for BART purposes. PCS Nitrogen has the potential to emit more than 

250 tons per year of ammonia from three of its BART eligible units and it is located less 

than 300 km from both Mingo and Sipsey. Thus these emissions were included in the PCS 

Nitrogen BART determination modeling. 

Justification of 0.5 dv contribution threshold for CALPUFF BART modeling (from 

Appendix L) 

In justifying the contributions threshold used in the BART exemption modeling the SIP 

argues that according the BART guidance, “States remain free to use a threshold lower 

than 0.5 deciviews if they conclude that the location of a large number of BART-eligible 

sources within the State and in proximity to a Class I area justify this approach.” 

....“causing” visibility impairment means having a humanly perceptible impact (for 

which EPA considers the practical threshold to be 1.0 dv) while “contributing” to 

visibility impairment means having a smaller impact (for which EPA considers the 

threshold to be 0.5 dv or some smaller value) that may or may not be perceptible. The 

EPA argues that a contribution threshold of less than 0.5 dv impact per source is 

appropriate when multiple sources contribute, in order to limit the combined effect of 

these sources. As an example, EPA asserts that if there were 100 sources, each affecting 

visibility by 0.1 dv (presumably an imperceptible amount), their total impact would be 10 

dv (which can be expected to be quite perceptible).3

 The point remains that multiple 

sources can cause a larger impact than a single source. For BART purposes, visibility 

impacts are calculated as 24-hr averages of 1-hr plume impacts, so if the plumes from the 

various sources each impact the point of interest at some time during a 24-hr period (not 

necessarily all at the same hour) then the 24-hr average will reflect their combined 

impact. 

There is no cluster of Tennessee BART sources near the GRSM/JOKI area (Figure 3-1). 

Only two sources, TVA-Bull Run and Alcoa are located within 32 km from each other and 

the rest at over 100 km from one another with respect to these Class I areas. Similairly, 

Tennessee BART sources near the Memphis area (i.e., DuPont-Shelby, Lucite 

International and PCS Nitrogen) are all located greater than 180 km from the 

MING/SIPS/MACA Class I areas and they would not constitute a cluster of sources near 

a Class I area for plume convergence considerations. 

 

3

 70 FR 39121. 1st column 
62 

TDEC-APC concluded that the EPA suggested contribution threshold of 0.5 dv was 

appropriate in this situation since there are a limited number of out of state sources that 

impact the various Class I areas in the state. 

GRSM = Great Smoky Mountains National Park 

JOKI = JoyceKilmer -Slickrock 

MACA = Mammoth Cave, KY 

MING = Mingo, MO 

Data Access – Due to the excessive size of data and modeling files that constitute the 

BART modeling developed by the sources, the archival and access of this data is made 

available to the public upon request and is discussed in Appendix I.

EPA Findings: The State has appropriately identified the BART-eligible sources 

and those sources subject to BART controls. It successfully developed and provided the 

technical analyses to support the BART assessment provision for the non-CAIR sources. 

However, Tennessee opted to have CAIR satisfy BART for SO2 and NOx for affected 

CAIR EGUs, as allowed under the Regional Haze regulations. As explained in Section 

III.C.1–EPA Findings,, the State’s demonstration regarding CAIR and reasonable progress 

for EGUs, and other provisions in this SIP revision, are based on CAIR and thus, the Agency 

proposes to issue a limited approval and a proposed limited disapproval of the State’s 

regional haze SIP revision.

The CALPUFF4

 modeling system was appropriately applied by TDEC-APC in 

the assessment of visibility impairment in Class I areas for specific sources subject to the 

BART Rule. The BART Rule indicates that CALPUFF or other appropriate models can 

be used to determine if an individual source is anticipated to cause or contribute to 

impairment of visibility in Class I areas. It is important to note that the current regulatory 

niche for the CALPUFF modeling system in 40 CFR, Part 51, Appendix W: Guideline on 

Air Quality Models (Appendix W) is for compliance with NSR/PSD permitting 

requirements for long range transport (i.e., greater than 50 KM) applications at Class I 

areas. There is no preferred model for assessing visibility impact under BART. 

However, it is appropriate for the State of Tennessee to use the CALPUFF modeling 

system for its BART exemption and control determination modeling. 

The Visibility Improvement State and Tribal Association of the Southeast 

(VISTAS) developed a “Protocol for the Application of CALPUFF for BART Analyses.” 

The final VISTAS BART Modeling Protocol (Revision 3.2, dated Aug. 6, 2006) states 

that VISTAS will use CALPUFF ver. 5.754 and CALMET ver. 5.7 (aka, the VISTAS 

version of CALPUFF). No formal approval of the CALPUFF VISTAS version (either 

ver. 5.754 or 5.756) has been made by Region 4. However, there has been an implied 

acceptance of the VISTAS CALPUFF version as Region 4 has reviewed and commented 

on the VISTAS BART Modeling Protocol and the source-specific modeling protocols 

 

4

 Note that our reference to CALPUFF encompasses the whole CALPUFF modeling system, including 

CALMET/CALPUFF/CALPOST and other pre and post processors. The different versions of CALPUFF 

have corresponding versions of CALMET, CALPOST, etc. which may not be compatible with previous 

versions (e.g., the output from a newer version of CALMET may not be compatible with an older version 

of CALPUFF). The different versions of the CALPUFF modeling system are available from the model 

developer on the following website: http://www.src.com/verio/download/download.htm 
63 

and reports that were developed by the Tennessee specific sources performing BART 

modeling. The VISTAS BART modeling protocol underwent an extensive stakeholder 

development and review process, that involved EPA, FLMs, industrial sources, trade 

groups, lawyers and other interested parties, before the state decided to require 

CALPUFF modeling to evaluate the BART requirements. 

The state required all BART-eligible sources to perform BART exemption 

modeling and to develop source-specific protocols that complied with the VISTAS 

protocol. EPA Region 4 provided reviews and comments on the source-specific 

protocols and their subsequent exemption modeling reports. The exemption protocols 

and modeling reports are presented in Appendix L of the Tennessee Regional Haze SIP. 

The CALPUFF model was simulated with the default inputs as recommended in 

the March 16, 2006 EPA memorandum, “Dispersion Coefficients for Regulatory Air 

Quality Modeling in CALPUFF. “ A new methodology was used by the VISTAS States 

to process the mass concentrations from CALPOST (post-CALPUFF processor) using the 

new IMPROVE equation so that the BART analyses could consider both the old and new 

IMPROVE equations. The U.S. Environmental Protection Agency (EPA) Headquarters 

and other EPA Regional Offices and the Federal Land Managers (FLMs) from the 

National Park Service and the U.S. Fish and Wildlife Service consulted on the VISTAS 

innovative approach that was developed to utilize the new IMPROVE equation in the 

BART assessment and to determine the change in visibility impacts. It should be noted 

that while these other parties were consulted in preparation of EPA Region 4’s response, 

the response represented the EPA Region 4 position on the new methodology. Use of the 

methodology by BART sources in States located in other EPA Regions would require 

consultation with the appropriate regional office. EPA required the State of Tennessee to 

submit a request to the EPA Regional Administrator requesting the use of this new 

methodology for the BART CALPUFF-based modeling. A September 13, 2007 letter 

justifying the need for this approach was sent and approval from the Regional 

Administrator was provided to the state on October 5, 2007. The methodology and state 

and Region 4 letters are located in the state’s TSD. 

The state was required to justify their choice of the 0.5 dv contribution threshold 

for exempting sources from BART eligibility. EPA agrees with the state’s rationale for 

choosing this threshold value since there are a limited number of in and out of state 

sources that impact the various Class I areas in the State. In addition there are a limited 

number of sources in close proximity to each of the Class I areas. Considering results of 

the visibility impacts modeling conducted (see Section 7of Appendix L), a 0.5 dv 

threshold was appropriate and a lower threshold was not warranted since the majority of 

the visibility impacts were well below 0.5 deciviews. Also, even though several sources 

impacted each Class 1 area, the overall impacts were low from the BART sources, and 

we have not made any adverse comments on the use of the CALPUFF VISTAS versions. 

Note that our reference to CALPUFF encompasses the whole CALPUFF 

modeling system, including CALMET/CALPUFF/CALPOST and other pre and post 

processors. The different versions of CALPUFF have corresponding versions of 

CALMET, CALPOST, etc. which may not be compatible with previous versions (e.g., 

the output from a newer version of CALMET may not be compatible with an older 

version of CALPUFF). The different versions of the CALPUFF modeling system are 
64 

available from the model developer on the following website: 

http://www.src.com/verio/download/download.htm 

References used in the EPA review: 

1. 40 CFR Part 5, Appendix W: Guideline on Air Quality Model 

2. October 5, 2007 letter from James I. Palmer, Regional Administrator, US EPA 

Region 4, to Barry Stephens, TDEC-APC, the use of the VISTAS methodology for 

use of the New IMPROVE equation with CALPUFF model results. 

3. BART Guidelines 

4. IWAQM. 1998. Interagency Workgroup on Air Quality Modeling (IWAQM) 

Phase 2 Summary Report and Recommendations for Modeling Long-Range 

Transport and Impacts on Regional Visibility. EPA-454/R-98-019. U.S. 

Environmental Protection Agency, Office of Air Quality Planning and Standards, 

Research Triangle Park, NC. 

5. VISTAS, 2006. Tombach, I., P. Brewer, T. Rogers, and C. Arrington, Protocol 

for the Application of the CALPUFF Model for Analysis of Best Available Retrofit 

Technology (BART) Revision 2 – 3/9/06 developed through consultation with 

EPA, the FLMs, VISTAS state and local Agencies and industry stakeholders 

VISTAS, 2006. Tombach, I., P. Brewer, T. Rogers, and C. Arrington, Located at 

http://www.vistassesarm.org/documents/BARTModelingProtocol_rev3.2_31Aug06.pdf. 

6. March 16, 2006 EPA memo from Dennis Atkinson to Kay T. Prince on 

Dispersion Coefficients for Regulatory Air Quality Modeling in CALPUFF

7. Additional Regional Haze Questions - September 27, 2006 Revision. Informal 

questions and answers developed by EPA Regional Offices Workgroup and 

shared with States and Tribal Agencies, FLMs and industry stakeholders. 

8. Appendix Y to 40 CFR Part 51, the Guidelines for BART Determinations Under 

the Regional Haze Rule
65 

III. Evaluation of State Regional Haze Submittal 

D. Best Available Retrofit Technology (BART) Requirements

D.3. Identification of Sources Addressed by CAIR Rule: States which adopt the 

CAIR cap and trade program for SO2 and NOx are allowed to apply CAIR controls as a 

substitute for controls required under BART. The implementation plan should include a 

list of all BART-eligible sources within the State for which the CAIR rule is being 

applied. 

State Regional Haze Submittal 

Page 65 

Two of Tennessee’s BART-eligible sources are EGUs. These are TVA-Bull Run and TVACumberland Fossil Plants. These two sources have already installed or are installing 

scrubbers to reduce SO2 and Selective Catalytic Reduction (SCRs) to reduce NOx. 

The USEPA has determined that, as a whole, the CAIR cap-and-trade program improves 

visibility more than implementing BART for individual sources in states affected by 

CAIR. A State that opts to participate in the CAIR program under 40 CFR 96.201-.224 

(Subpart AAA through EEE) need not require affected BART-eligible EGU to install, 

operate, and maintain BART for SO2 or NOx emissions. Given that all BART-eligible 

units are installing scrubbers and NOx controls, and since Tennessee is participating in 

CAIR and accepts USEPA’s overall finding that CAIR “substitutes” for BART for NOx 

and SO2, Tennessee’s EGUs were allowed to submit BART exemption modeling 

demonstrations for PM emissions only. TVA-Bull Run demonstrated that it does not 

contribute to visibility impairment in any Class I area. 

EPA Findings: Tennessee has not completely and appropriately addressed this 

provision. The State has appropriately identified the BART-eligible sources and those 

sources subject to BART controls. However, Tennessee opted to have CAIR satisfy 

BART for SO2 and NOx for affected CAIR EGUs, as allowed under the Regional Haze 

regulations. However, as explained in Section III.C.1–EPA Findings,, the State’s 

demonstration regarding CAIR and reasonable progress for EGUs, and other provisions in 

this SIP revision, are based on CAIR and thus, the Agency proposes to issue a limited 

approval and a proposed limited disapproval of the State’s regional haze SIP revision. 
66 

III. Evaluation of State Regional Haze Submittal 

D. Best Available Retrofit Technology (BART) Requirements

D.4. Source Specific BART Determinations: For each BART-eligible source in the 

State subject to BART, a determination of BART based on an analysis of the best system 

of continuous emission control technology available and associated emission reductions 

achievable (unless the State demonstrates that an emissions trading program or other 

alternative will achieve greater reasonable progress toward natural visibility conditions). 

To address the requirements for BART, the State must take into consideration all of the 

“Five Factors” from 51.308(e)(1)(ii)(A): (1) the technology available, (2) the costs of 

compliance, (3) the energy and non-air quality environmental impacts of compliance, any 

pollution control equipment in use at the source, (4) the remaining useful life of the 

source, and (5) the degree of improvement in visibility that may reasonably be anticipated 

to result from the use of such technology. 

State Regional Haze Submittal 

Pages 66-70 

Four (4) sources, Eastman Chemical in Kingsport, Tennessee, Alcoa-South Plant in 

Alcoa, Tennessee, TVA – Cumberland Fossil Plant in Cumberland City, Tennessee and 

DuPont in Old Hickory, Tennessee were unable to demonstrate a contribution of less 

than 0.5 dv at all Class I areas within 300 km from their BART-eligible sources. These 

four sources are considered to be “subject to BART” and have submitted analyses 

containing their evaluation of potential BART options and proposed BART 

determinations. 

The proposed BART determinations have been reviewed by the TDEC-APC. In addition, 

comments from USEPA regarding the source’s self-analysis were received and discussed 

with the sources. The source self-analysis, USEPA’s comments, the source’s response 

to those comments and TDEC-APC’s position on those comments appear in Appendix 

L. 

From those determinations, permit conditions have been developed for each BART 

facility. Upon USEPA’s final approval of the Tennessee Regional Haze SIP as 

announced in the Federal Register thereby constituting approval the following BART 

permit conditions, said conditions will be inserted into the facility’s Part 70 Title V 

Operating Permit as a new applicable requirement. The timing of adding these federally 

approved permit conditions will be done consistent with the permit reopening provisions 

of the Tennessee rules that implement Part 70. Any reference to Part 70 or Tennessee’s 

rules that implement Part 70 are merely to explain the vehicle and timing of the permit 

action and not to offer them for inclusion into the Regional Haze SIP. The permit 

conditions listed below will become applicable requirements and are offered for federal 

approval into Tennessee’s Regional Haze SIP. Pursuant to Division Rule 1200-3-23-

.05, actual operating permits for the sources are presented in Appendix L-12. Like the 

aforementioned permit conditions, these permits will become effective upon USEPA’s 

final approval of the Tennessee Regional Haze SIP and serve until such time that they 
67 

can be added to the facilities’ Part 70 permits as a new applicable requirement as 

described above. 

For Eastman, BART will include a more stringent sulfur dioxide limitation on its boilers 

that necessitates the addition of control equipment. 

Eastman Chemical Company BART Permit Condition for inclusion into the 

Tennessee Regional Haze SIP 

Powerhouse B-253-1, Boilers #25-#29, BART Requirements 

Emission Limitation: No later than five (5) years after publication in the 

Federal Register of U. S. EPA’s approval of Tennessee’s Regional Haze 

State Implementation Plan revision, sulfur dioxide (SO2) emissions from 

Boilers 25-29 shall comply with the less stringent of the following limits: 

1. 0.20 pounds of SO2 per million British Thermal Units (lb/MMBtu) of 

heat input; or 

2. Reduce uncontrolled SO2 emissions by 92%. 

Compliance with these emission limits shall be determined on a thirty (30) 

calendar day rolling average basis as the average emission rate, or 

average SO2 reduction, from either each boiler individually while 

combusting coal, or averaged across all of the boilers that are combusting 

coal. 

Compliance Assurance Monitoring Requirements:

Measurement of SO2 emissions: SO2 emissions shall be measured 

through the use of continuous in-stack monitoring for sulfur dioxide, 

as specified below: 

The source owner or operator shall install, maintain, operate, and 

submit quarterly reports of excess emissions and sulfur dioxide 

(SO2) removal efficiency (if applicable) from continuous in-stack 

monitoring systems for sulfur dioxide (SO2). The sulfur dioxide 

monitoring systems shall meet all the requirements of 40 CFR 60 

Appendices A and B, or 40 CFR Part 75 Appendices A and F. 

Compliance will be determined on a 30 calendar day rolling average 

basis. Each 30 calendar day average shall be the average of the 

valid daily averages during the previous thirty (30) calendar days 
68 

Operational requirements for Sulfur Dioxide (SO2) Monitoring 

Systems: For this fuel burning installation to demonstrate continual 

compliance with the BART sulfur dioxide emission limitation, each 

sulfur dioxide monitoring system for boilers #25-#29 shall be fully 

operational for at least ninety five percent (95%) of the operational 

time (during which coal is combusted) of the monitored units during 

each calendar quarter. Operational availability levels of less than 

these amounts may be considered the basis for declaring the fuel 

burning installation in noncompliance with the applicable monitoring 

requirements, unless the reasons for the failure to maintain these 

levels of operational availability are accepted by the Technical 

Secretary as being legitimate malfunctions of the instruments. Data 

recorded during periods of monitoring system breakdown, repairs, 

calibration checks, and zero and span adjustments shall not be 

included in the data averages. 

 Quality Assurance requirements for the Sulfur Dioxide (SO2) 

Monitoring Systems: The continuous in-stack sulfur dioxide 

monitoring systems shall meet all of the requirements of 40 CFR 

Part 60 Appendix B (Performance Specification 2) and 40 CFR Part 

60 Appendix F; or 40 CFR Part 75 Appendices A and B. 

 

Monitoring Plan: Monitoring shall be conducted as specified in an 

approved site-specific monitoring plan. The monitoring plan must be 

submitted to the Technical Secretary at least ninety (90) days prior to 

the startup of the control device. 

Recordkeeping: All records required to demonstrate compliance 

with this condition shall be maintained at the source location and 

kept available for inspection by the Technical Secretary or his 

representative. Records shall be maintained for five (5) years. 

For Alcoa, the final BART determination resulted in an agreed upon limitation of 3% 

sulfur in the petroleum coke used in the facility’s electrode production operations and 

thus, used in their aluminum potlines. Alcoa envisions that it will still be in operation in 

2064. Alcoa will continue to evaluate long-term options for reducing SO2 emissions 

including pollution controls and process changes. Progress updates on emerging options 

will be provided to TDEC-APC as pertinent with a formal update to be provided no later 

than five years after the USEPA’s approval of the SIP. The progress updates are not 

intended to be an enforceable commitment. Instead, they will be used to keep TDECAPC apprised of the company’s efforts. Those reports may also form the basis for 

determining whether or not more stringent controls are warranted in the future progress 

reviews. 

Alcoa BART Permit Condition for inclusion into the 
69 

Tennessee Regional Haze SIP 

Emission Limitation: No later than five (5) years after publication in the Federal 

Register of U.S. EPA’s approval of Tennessee’s Regional Haze State 

Implementation Plan revision, the sulfur content of coke used to produce anodes 

shall not exceed 3 percent by weight on a monthly average. 

Compliance Methodology: Compliance with this limitation shall be assured by 

maintaining records of the sulfur content of petroleum coke used to make 

anodes. All records required to demonstrate compliance with this condition shall 

be maintained at the source location and kept available for inspection by the 

Technical Secretary or his representative. Records shall be maintained for five 

(5) years. 

For TVA Cumberland Fossil Plant, TDEC-APC has determined that no additional 

controls for visibility impairing pollutants will be required as the facility is currently well 

controlled with flue gas desulfurization technology and oxides of nitrogen reduction 

technology. 

TVA Cumberland Fossil Plant BART Permit Condition for inclusion into the 

Tennessee Regional Haze SIP 

BART Requirements 

Emission Limitation for BART: Sulfur dioxide (SO2) emissions from Boilers 

No. 1 and 2 shall comply with the following limit: 

0.5 pounds of SO2 per million British Thermal Units (lb/MMBtu) of heat 

input 

 Compliance with this emission limit shall be determined on a thirty (30) calendar day 

rolling average basis averaged across both boilers. 

Compliance Assurance Monitoring Requirements:

Measurement of SO2 emissions: SO2 emissions shall be measured 

through the use of continuous in-stack monitoring for sulfur dioxide, 

as specified below: 

The source owner or operator shall install, maintain, operate, and 

submit quarterly reports of excess emissions and sulfur dioxide 

(SO2) removal efficiency (if applicable) from continuous in-stack 

monitoring systems for sulfur dioxide (SO2). The sulfur dioxide 
70 

monitoring systems shall meet the availability and quality assurance 

requirements specified in this permit. 

Compliance will be determined on a 30 calendar day rolling average basis. Each 

30 calendar day average shall be calculated from the valid daily averages during 

the previous thirty (30) calendar days 

Recordkeeping: All records required to demonstrate compliance 

with this condition shall be maintained at the source location and 

kept available for inspection by the Technical Secretary or his 

representative. Records shall be maintained for five (5) years. 

For Dupont Old Hickory, the facility proposes limiting the total combined daily 

emissions for Boilers 20 and 24 based upon the following operating limits stated below. 

Dupont Old Hickory BART Permit Condition for inclusion into the 

Tennessee Regional Haze SIP 

1. Name of source facility and the specific emission units and 

pollutants being controlled. (40 CFR 51.308(e)(1)(i)&(ii)). 

• E. I. du Pont de Nemours and Company, Old Hickory Site 

• Units 47-037-00002-009 (Boiler 20) and 47-037-00002-011 (Boiler 

24) 

• Pollutants being controlled: Sulfur dioxide and Nitrogen oxide 

2. Specifics of the controls, control efficiency(ies), emission reductions 

expected. 

E. I. du Pont de Nemours is reducing allowable sulfur dioxide emissions 

from the affected units by 20,834 pounds/day in the summer (May – 

September) and 14,522 pounds/day in the winter (October – April). The 

facility is reducing allowable nitrogen oxide emissions from these units by 

3,978 pounds/day in the summer and 3,330 pounds/day in the winter. 

3. Enforceable emission limitations representing BART (40 CFR 

51.308(d)(3);(e)). 

 Allowable emission limitations* 

 Sulfur dioxide Nitrogen oxides 

 (pounds/day) (pounds/day) 

Summer (May – 32,256 6,120 
71 

September): 

Winter (October – April): 38,568 6,768 

* Combined emissions from both units 

4. Schedules for compliance with BART (40 CFR 51.308(d)(3);(e)) 

E. I. du Pont de Nemours and Company, Old Hickory Site will be in 

compliance with the applicable emission limitations as expeditiously as 

practicable, but in no event later than five (5) years after publication in the 

Federal Register of U.S. EPA’s approval of Tennessee’s Regional Haze 

State Implementation Plan revision. 

5. A requirement that each source subject to BART maintains the 

control equipment and establishes procedures to ensure such 

equipment is properly operated and maintained. (40 CFR 

51.308(e)(v)) 

N/A 

6. Reporting, monitoring, and recordkeeping requirements adequate to 

determine the source’s compliance (40 CFR Part 51, Appendix Y-V). 

The source will be required to maintain adequate records of fuel burning 

rates and fuel sulfur contents to demonstrate compliance with the 

applicable daily emission standards using the following equation: 

Where: 

MC20 = Mass of coal burned in Boiler No. 20, tons per day 

MC24 = Mass of coal burned in Boiler No. 24, tons per day 

VNG20 = Volume of natural gas burned in Boiler No. 20, 106 cubic feet per 

day 

VNG24 = Volume of natural gas burned in Boiler No. 24, 106

 cubic feet per 

day 

VFO20 = Volume of fuel oil burned in Boiler No. 20, 1,000 gallons per day 

VFO24 = Volume of fuel oil burned in Boiler No. 24, 1,000 gallons per day 

EFC20 = Emission factor for coal burning in Boiler No. 20, pounds per ton 

EFC24 = Emission factor for coal burning in Boiler No. 24, pounds per ton 

EFNG20 = Emission factor for natural gas burning in Boiler No. 20, pounds 

per 106

 cubic feet 

[( )( )( ) MC20 ⋅ EFC20 + VNG20 ⋅ EFNG20 + VFO20 ⋅ EFFO20 + (MC24 ⋅ EFC24 )+ (VNG24 ⋅ EFNG24 )( ) + VFO24 ⋅ EFFO24 ] ≤ EL
72 

EFNG24 = Emission factor for natural gas burning in Boiler No. 24, pounds 

per 106 cubic feet 

EFFO20 = Emission factor for fuel oil burning in Boiler No. 20, pounds per 

1,000 gallons 

EFFO24 = Emission factor for fuel oil burning in Boiler No. 24, pounds per 

1,000 gallons 

EL = Applicable emission limit, pounds of pollutant per day 

7. All records must be maintained on site and made available for 

inspection upon request. Records must be retained for at least five 

years. The source will be required to report any excess emissions, 

including those attributed to upset conditions, the probable cause of 

such deviations, and any corrective actions or preventative measures 

taken, to the permitting authority within one (1) to (10) days from the 

date on which the deviation occurs. Averaging times and 

reference methods to determine compliance (40 CFR Part 51, 

Appendix Y – V). 

The allowable emission limitations are based on a maximum 24-hour 

standard beginning at midnight each calendar day. 

For a more detailed discussion of the aforementioned BART determinations, please see 

Appendix L. 

Pages L.30-L.57 

8.1.1.1 Alcoa - BART-eligible Units and Existing Control

Alcoa has twenty-four BART-eligible emission units that comprise the BART-eligible 

source. The majority of these units are currently controlled. A description of these units 

taken from the Alcoa BART demonstration submittal (See Appendix L-8) follows. 

Table 8.1.1.1 Primary Aluminum Reduction Emission Units, Alcoa Inc. – Tennessee 

Operations 

Emission 

Unit ID Emission Unit Description 

Visibility 

Impairing 

Pollutants 

Existing 

Pollution 

Controls 

05-0008-81 Potline 1 Electrolytic reduction operations that convert 

alumina and other raw materials to molten 

aluminum in the potline. 

PM, SO2 Reactor / 

Fabric Filter 

05-0008-85 Potline 2 Electrolytic reduction operations that convert 

alumina and other raw materials to molten 

aluminum in the potline. 

PM, SO2 Reactor / 

Fabric Filter 

05-0008-18 Anode Baking 

Furnace 

This emission unit includes the 261N, 262N, 

and 262S anode baking furnaces, which are 

controlled by the A-446. 

PM, SO2, NOX Reactor / 

Fabric Filter 
73 

Table 8.1.1.1 (Continued) 

Emission 

Unit ID Emission Unit Description 

Visibility 

Impairing 

Pollutants 

Existing 

Pollution 

Controls 

05-0008-02 Coke 

Unloading and 

Storage 

This emission unit includes operations that 

unload virgin coke from railcars and store it 

for feed to the Electrode Plant "A” 

operations. Emissions are controlled by dust 

collector 8. 

PM Fabric Filter 

05-0008-03 Electrode 

Plant A 

This emission unit includes all operations 

controlled by baghouse 12, which include the 

screening and blending of virgin coke and 

ground anode butts and green scrap before 

feeding to the carbon paste mixers. 

PM Fabric Filter 

05-0008-12 Stub Dipping This emission unit covers the operation where 

anode rods are dipped into a coating to 

ensure separation of cast iron. 

Volatile Organic 

Compounds 

05-0008-14 Butts Blasting Butts blasting uses a blasting media to remove 

residual bath from the spent anodes following 

butts cleaning. Emissions are controlled via a 

dust collector. 

PM Fabric Filter 

05-0008-16 Induction 

Furnaces 

This emission unit covers the process of 

melting cast iron and pouring it into the 

anodes to bond the rods to the anode blocks. 

Emissions are controlled via baghouse. 

PM, SO2 Fabric 

Filter 

05-0008-19 Ball Mill This emission unit receives carbon that is to 

be pulverized by the Electrode Plant "A” 

operations, crushes these, and returns the 

carbon fines. Emissions are controlled by dust 

collector 10. 

PM Fabric Filter 

05-0008-20 Pitch Tanks 

Coal Tar Pitch Storage Tanks 217A, B, and C. 

Volatile Organic 

Compounds 

05-0008-26 Stripping 

Presses 

This emission unit includes two stripping 

presses that remove the carbon and cast iron 

from the anode assemblies following the butts 

blasting operation. 

PM Fabric Filter 

05-0008-30 Butts 

Intermediate 

Classifying 

System 

This emission unit is currently idled. When 

operable, it serves as a classifying system for 

intermediate-sized recycled carbon. Emissions 

are controlled via dust collector 9. 

PM Fabric Filter 
74 

05-0008-31 Ore 

Unloading, 

Trans. and 

Storage 

This emission unit covers unloading of raw 

materials, bulk storage of those materials, and 

transfer to the potline 1 and 2 material 

handling systems (process weight rate is 300 

tons/hour). This emission unit includes soda 

storage tank 141L, conveyor B-4, conveyor B4A, tower 3A, conveyor B-2, fresh ore tank 

142N, fresh ore tank 142S, fresh ore tank 

143N, fresh ore tank 143S, feed tank 141A, 

fluoride storage tank 141F, feed tank 141K, 

feed tower 2, rail unloading, and conveyor B5 discharge/B-6. All emission points are 

controlled with dust collection except fluoride 

storage tank 141F and soda storage tank 

141F, which are uncontrolled and identified 

as insignificant emission units. 

PM Fabric Filter 

Table 8.1.1.1 (Continued) 

Emission 

Unit ID Emission Unit Description 

Visibility 

Impairing 

Pollutants 

Existing 

Pollution 

Controls 

05-0008-33 Bath 

Crushing/ 

Crucible 

Digging 

This emission unit covers the operations 

receiving bath from butts cleaning and 

crucible digging, and includes bath crushing, 

storage, and mixing with alumina for return to 

the potlines, transfer, or sales. This emission 

unit includes a bucket fill station. 

PM Fabric Filter 

05-0008-51 Carbon 

Reclamation 

This emission unit is baghouse controlled. The 

process weight rate 150,000 lb/hour. 

PM Fabric Filter 

05-0008-54 Packing 

Material 

Handling 

This emission unit includes railcar unloading 

of virgin packing material and storage and 

transfer of clean and recycled packing 

material for use in the anode baking furnaces 

and is baghouse controlled. 

PM Fabric Filter 

05-0008-62 Butts Cleaning Butts cleaning removes bath from the spent 

anodes and is the first step in the carbon 

reclamation process. This emission unit is 

baghouse controlled. 

PM Fabric Filter 

05-0008-98 Initial Carbon 

Paste Mixing 

Operations 

and Green 

Mill Anode 

Forming 

This emission unit receives virgin and 

recycled carbon and mixes these with pitch to 

form a paste. The paste is compacted into the 

shape of new green anodes. 

PM, Volatile 

Organic 

Compounds 

Reactor / 

Fabric Filter 

05-0008-10 Potline I 

Material 

Handling 

(North 

Courtyard) 

Alumina feed tanks 142NE and 142NW, 

airlifts 142NE and 142 NW, and dust 

collectors. 

PM Fabric Filter 

05-0008-39 Potline I 

Material 

Handling 

Alumina feed tanks 142SE and 142SW, airlifts 

142SE and 142 SW, and dust collectors. 

PM Fabric Filter 
75 

05-0008-43 Potline I 

Material 

Handling 

Alumina feed fill station, air slide 101S, air 

slide 102S, air slide 101N, air slide 102N, 

north discharge air slide, and south discharge 

air slide. 

PM Fabric Filter 

05-0008-44 Potline II 

Material 

Handling 

Conveying and storage of raw materials for 

potline 2. The emission unit includes air lift 

146N, air lift 146S, air slide 103N, air slide 

103S, air slide 104N, air slide 104S, ore tank 

146N, and ore tank 146S. 

PM Fabric Filter 

05-0008-47 143N-TP002 

LII North 

Conveying of raw materials for potline 2. PM Fabric Filter 

05-0008-86 143S-TP002 

LII South 

Conveying of raw materials for potline 2. PM Fabric Filter 

Potlines 1 and 2 emit SO2 and particulate matter (PM), and the anode bake 

furnace emits lesser amounts of SO2, nitrogen oxides (NOX), and PM. These three 

emission units are already equipped with sophisticated emission control equipment for 

PM, so the BART determination for these emission units focuses primarily on potential 

reductions for SO2 and NOX. 

The remaining 21 emission units identified in Table 8.1.1.1 are material handling 

and transfer operations that support the potlines and the anode bake furnace. Two of 

these support operations are negligible sources of volatile organic compounds. 

Emissions from 19 of these support operations consist of relatively small amounts of PM 

that are controlled by fabric filter type control devices. Fabric filters effectively remove 

>99% of particulate emissions and, based on a control technology review, represent the 

best available control for these types of material handling and transfer operations. Given 

the level of emissions and that fabric filters represent the best available control, these 

emission sources were excluded from both visibility modeling and further BART 

engineering analysis. Based on visibility modeling results for the aluminum reclamation 

melting furnaces, which have a comparable PM emission rate, visibility impacts from 

individual fabric filters are projected to be ≤0.01 deciviews (dv). BART for these support 

operations was determined to be the existing level of control. 

8.1.1.2 Eastman Chemical - BART-eligible Units and Existing Control

MSOP PES Vent ID Emission Unit NOx SO2 
76 

Table 8.1.1.2 shows the list of BART-eligible units that are located at Tennessee Operations (TNO) in Kingsport, TN. This table 

includes general information on the size and emissions of the emission units. Specific information on stack parameters and 

maximum daily emissions of the emission units is included in the BART Modeling Protocols (included as Appendix L-6). 

8.1.1.2.1 BART Control Options Review and Analysis 

1.1 Building 253 Powerhouse, Coal-fired Boilers #25-#29 

1.1.1 Emission Unit Description 

These five boilers are located side-by-side in Building 253 at the 

Kingsport plant. All of these boilers are Combustion Engineering 

tangentially-fired pulverized coal boilers started up between 1966 

and 1972. They are rated at a maximum heat input capacity of 655 

MBtu/hr. Eastern Kentucky and western Virginia type bituminous 

coal is the only fuel burned in these units (other than natural gas 

for startups). 

These units are used for co-production of steam and electricity in 

support of manufacturing operations at the Kingsport plant. A 

high level of reliability and the ability to handle boiler load swings 

are requirements for any emissions control system. Although these 

2005 Actual 

Emissions 

Allowable Existing 

Controls 

2005 Actual 

Emissions 

Allowable Existing 

Controls 

Tons Basis Tons Basis 

Coal-fired industrial boilers 

02 B-253-

1 

A-E Boilers #25 - 

#29(pulverized 

coal, 

tangentially 

fired, 655 

MBtu/hr each) 

4,555 CEMS N/A LNB 

(ozone 

season) 

14,309 CEMS 2.4 

lb/MBtu 

Sulfur 

content 

02 B-83-1 C Boiler 24 

(overfeed 

stoker, 500 

MBtu/hr) 

569 CEMS N/A None 1,494 Fuel 

Usage, 

Sulfur 

Content 

2.4 

lb/MBtu 

Sulfur 

content 

Cracking Furnaces (Natural Gas-Fired) 

16 B-6C-1 A Furnace 27 

(18 MBtu/hr) 

6.5 AP42, 

Fuel 

Usage 

10.6 tpy None 0.16 AP-42, 

Fuel 

Usage 

0.5 tpy Sulfur 

content 

16 B-6C-1 B Furnace 28 

(18 MBtu/hr) 

6.5 AP42, 

Fuel 

Usage 

10.6 tpy None 0.16 AP-42, 

Fuel 

Usage 

0.5 tpy Sulfur 

content 

Others 

25 OCBATCH Various 

(see Title V 

application) 

General 

Purpose Batch 

Chemical 

Manufacturing 

 14.0 tpy Scrubbers 7.2 tpy Scrubbers 
77 

units are typically base loaded, at times individual boiler load can 

swing as much as 100 klb/hr in a minute or two in response to a 

steam or electric load upset. 

Existing Particulate Matter Controls: Each boiler has a five field 

electrostatic precipitator (ESP) with collecting area of 167,416 ft2 

and a design flue gas flow rate of 286,000 acfm. The electrostatic 

precipitators are located at ground level. These precipitators were 

installed in the early 1990s. 

Existing NOx Controls: During 2001-2003, the burners on these 

boilers were retrofitted with the Alstom P2 system. This system 

incorporates vaned close-coupled overfire-air (separates the upper 

end auxiliary air from the fire creating a mini-SOFA within the 

windbox) with modified coal tips that provide for flame attachment 

closer to the burners. When fired in low NOx mode during the 

NOx SIP call ozone season (May through September), average 

NOx emission rates have run around 0.32 lb/MBtu. However, 

performance depends on boiler load. At high boiler loads, three 

mills operation is required. At lower loads, the boiler can run on 

only two mills. This latter mode of operation is, in essence, 

equivalent to a NOx control strategy know as Burner Out of 

Service (BOOS) and results in significantly lower NOx emissions. 

For our evaluations of further NOx control measures, we are 

assuming an average emission rate of 0.35 lb/MBtu to account for 

uncertainty in future boiler load demands dictated by unplanned 

outages or site steam load requirements. For a given control 

strategy, this assumption will result in higher estimates of emission 

reductions and correspondingly lower cost-effectiveness estimates. 

Existing SO2 Controls: Other than purchase of low to medium 

sulfur coal to meet the SIP limit of 2.4 lb/MBtu, there are no 

existing controls of sulfur dioxide emissions. The average 

emission rate for calendar year 2005 was 1.4 lb/MBtu. 

8.1.1.3 DuPont – Old Hickory - BART-eligible Units and Existing Control

The DuPont Old Hickory Plant Title V Air Permit includes the following information 

relative to the two BART-eligible boilers, Boilers 20 and 24: 

Source Description:

• Boiler 20- Rated capacity- 445 million Btu/hr; installation date- 1968; 

tangentially fired; primary fuel- coal; #1 standby fuel- natural gas; #2 standby 

fuel- No.2 Fuel Oil 
78 

• Boiler 24- Rated capacity- 315 million Btu/hr; installation date- 1966; 

tangentially fired; primary fuel- coal; #1 standby fuel- natural gas; #2 standby 

fuel- No.2 Fuel Oil 

Mass and Visible Emission Standards and Operating Schedule Limitations

• Boilers 20 and 24- visible emission standard- 20% 

• Boilers 20 and 24- operating schedule limitations- 24 hrs/day, 8,760 hr/year 

• Boiler 20 (Emission Point 009) mass emission standards: 

Pollutant Lb/hr Lb/day Rolling 12 Month 

Tons 

PM10 77.4 1858 339.1 

SO2 1295.2 31,086 5673 

NOx 241.2 5789 1056.4 

CO 10.4 251 45.7 

VOC 2.4 57 10.51 

• Boiler 24 (Emission Point 011) mass emission standards: 

Pollutant Lb/hr Lb/day Rolling 12 Month 

Tons 

PM10 54.8 1315 240.1 

SO2 916.9 22,004 4015.8 

NOx 179.6 4309 786.4 

CO 7.4 177 32.4 

VOC 1.7 41 7.45 

• Boilers 20 and 24 are subject to MCL 10.56.200 (Davidson County-Local 

Program) which limits the maximum sulfur content of any solid or liquid fuel to 

2.0% sulfur by weight. The above standards are based on a maximum sulfur 

content of 0.05% by weight for No.2 Fuel Oil. 

• Boilers 20 and 24 are subject to 40 CFR 75, Subpart H, NOx Budget Trading 

Program. 

• All boilers are subject to 40 CFR 63, Subpart DDDDD, Industrial, Commercial, 

and Institutional Boilers and Process Heaters with a compliance date of 

September 13, 2007. 

The two Boilers at DuPont’s Old Hickory Plant in Old Hickory, TN are BART eligible 

based on their installation date and design heat input as indicated above. These Boilers 

are designated Boiler 20 and Boiler 24. The emissions from these boilers were modeled 

to determine the possible visibility impact on nearby Class 1 areas. 

8.1.1.4 TVA – Cumberland - BART-eligible Units and Existing Control
79 

The TVA Cumberland Fossil Plant (CUF), located in Stewart County, TN, has two 

pulverized-coal-fired steam generators that are considered BART eligible. Units 1 and 2 

are nominally rated at about 1325 MW each. Both units are equipped with flue gas 

desulfurization (FGD) systems for sulfur dioxide (SO2) control, selective catalytic 

reduction systems for controlling nitrogen oxides (NOx), and electrostatic precipitators 

(ESPs) to control particulate matter (PM) emissions. In addition, CUF currently uses 

hydrated lime injection on both units to mitigate stack opacity. 

The two units at CUF are subject to the EPA Clean Air Interstate Rule (CAIR). Based on 

guidance from EPA and TDEC-APC, compliance with CAIR satisfies BART requirements 

for SO2 and NOx emissions at electric generating units. As a result, the BART analysis 

only considerd PM10 emissions. 

Table 8.1.1.4 .1 Stack Parameters for CUF 

Table 8.1.1.4.2. Emissions profiles from SMOKE for EGUs (provided by VISTAS). 

profile Pllt species split divisor mass_frac 

22001 PM2_5 PEC 0.0183 1 0.0183 

22001 PM2_5 PMFINE 0.852 1 0.852 

22001 PM2_5 PNO3 0 1 0 

22001 PM2_5 POA 0.0107 1 0.0107

22001 PM2_5 PSO4 0.119 1 0.119 

Table 8.1.1.4.3 Emission Rates for CUF 1 and CUF 2 

Species CUF 1 Hydrated Lime Emission Rates (g/s) 

PM800 PM425 PM187 PM112 PM081 PM056 Total 

PM10 56.389 

PMC 3.3293 4.1126 7.44 

SOIL 2.2631 0.5658 0.3772 2.2630 5.47 

EC 0.0870 0.0217 0.0145 0.0869 0.21 

H2SO4 36.15 

Stack Parameter Unit 1 Unit 2 

Stack Height (m) 194 194 

Base Elevation (m) 118 118 

Stack Diameter (m) 11.7 11.7 

Gas Exit Velocity (m/s) 19.7 19.7 

Stack Gas Exit Temperature (oK) 321 321 
80 

SOA 3.5607 3.5607 7.12 

NO3/HNO3 0.00 

Species CUF 2 Hydrated Lime Emission Rates (g/s) 

PM800 PM425 PM187 PM112 PM081 PM056 Total 

PM10 79.053 

PMC 9.0798 11.2162 20.30 

SOIL 6.1721 1.5430 1.0287 6.1721 14.92 

EC 0.2371 0.0593 0.0395 0.2371 0.57 

H2SO4 36.15 

SOA 3.5607 3.5607 7.12 

NO3/HNO3 0.00 

Species CUF 1 and CUF2 Wet ESP Emission Rates (g/s) 

PM800 PM425 PM187 PM112 PM081 PM056 Total 

PM10 35.342 

PMC 4.5399 5.6081 10.148 

SOIL 3.0860 0.7716 0.5143 3.0860 7.458 

EC 0.1186 0.0296 0.0198 00.1186 0.287 

H2SO4 10.328 

SOA 3.5607 3.5607 7.121 

NO3/HNO3 0.00 

8.2 Baseline Contribution 

Alcoa’s BART source baseline contribution to visibility impairment is 1.31 dv at GRSM 

and 0.686 dv at JOKI. Eastman Chemical’s BART source baseline contribution to 

visibility impairment is 2.06 dv at LIGO, 2.55 dv at GRSM, 1.44 dv at SHRO, 1.67 dv at 

JOKI, 1.01 dv at COHU, and 0.79 dv at JARI. DuPont-Old Hickory’s source baseline 

contribution to visibility impairment is 0.504 dv at MACA. TVA-Cumberland’s BART 

source baseline contribution to visibility impairment is 1.359 dv at MACA and 0.557 dv 

at SIPS. 

8.3 BART Determination Analysis 

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. These factors are incorporated in the BART regulation and 

40 CFR Part 51 Appendix Y. Although these factors are to be considered, according to 

the BART guidelines states have flexibility in how the factors are weighted in making 

their determinations regarding what constitutes BART. (See 70 FR 39170, 1st col., July 6, 

2005.) 
81 

8.3.1 Control Scenarios Considered 

Each facility reviewed several potential control alternatives. These control alternatives 

considered and the associated visibility improvement that would result are summarized in 

Tables 8.3.1.1 through 8.3.1.6 below taken from the Alcoa, Eastman Chemical, TVACumberland, and DuPont-Old Hickory BART determination submittals respectively. 

Table 8.3.1.1 Alcoa - SO2 Post-Control Emission Ratesa

Control Scenario 

SO2 Control 

Technology 

SO2 NOX PM2.5 PM10 

Emissions 

(tons/year) 

% Reduction 

(Increase)b 

Emissions 

(tons/year) 

% 

Reduction 

(Increase)b 

Emissions 

(tons/year) 

% Reduction 

(Increase)b 

Emissions 

(tons/year) 

% Reduction 

(Increase)b 

1 3.5% Sulfur Coke 

with Potlines Wet 

Scrubber 

1,202 81 101 0 815 (116) 924 (87) 

2 3.0% Sulfur Coke 

with Anode Bake 

Furnace Wet 

Scrubber 

4,830 12c 101 0 413 (10)c 529 (7)c 

3 3.0% Sulfur Coke 

Potlines 

5,517 14 101 0 377 0 494 0 

and Anode 

Bake Furnace 

Current 3.5% Sulfur 6,436 101 377 494 

Potential Coke Potlines 

Emissions and Anode 

Bake Furnace 

a

Emission rates include the potline primary control system, the potline roof emissions, and 

the anode bake furnace. 

b

Compared with current potential emissions unless noted. c

Compared with 3.0% sulfur coke since this scenario would only occur with Control 

Scenario 3. 

Table 8.3.1.2 Alcoa BART Evaluation Visibility Impacts Summary 

Modeling 

 Scenario 

Modeled Visibility 

Impacts 

(dv) 

Visibility Improvement 

(delta -dv) 

Great 

Smokey 

Joyce 

Kilmer 

Great 

Smokey 

Joyce 

Kilmer 

Baseline 

(Current 3% Sulfur Coal 

w/ PTE 3.5% Sulfur Coal) 

1.310 0.686 -- -- 

Scenario #1 

(95% SO2 Control on Potlines 0.598 0.419 0.712 0.267 
82 

w/ Wet Scrubbers) 

Table 8.3.1.3 Eastman BART Evaluation Visibility Impacts Summary 

Modeling 

 Scenario 

Modeled Visibility 

Impacts 

(dv) 

Visibility Improvement 

(delta -dv) 

LIGO GRSM SHRO JOKI COHU JARI LIGO GRSM SHRO JOKI COHU JARI 

Baseline 

(Boilers 24-29)

2.06 2.55 1.44 1.67 1.01 0.79 - - - - - - 

Scenario #1 

(SDA/ESP at 

B-253) 

1.10 1.42 0.65 0.79 0.41 0.38 0.96 1.13 0.79 0.88 0.60 0.41 

Scenario #2 

(SDA/FF at B253)

0.87 0.99 0.54 0.47 0.29 0.29 1.19 1.56 0.90 1.20 0.72 0.50 

Scenario #3 

(Wet FGD at 

B-253)

0.85 0.97 0.53 0.45 0.28 0.25 1.21 1.58 0.91 1.22 0.73 0.54 

Scenario #4 

(Wet FGD at 

B-253 + Wet 

FGD at Boiler 

24)

0.65 0.87 0.45 0.37 0.23 0.24 1.41 1.68 0.99 1.30 0.78 0.55 

Scenario #5 

(Scenario 3 + 

LNB Yearround at B253)

0.67 0.79 0.38 0.36 0.23 0.23 1.39 1.76 1.06 1.31 0.78 0.56 
83 

 

Scenario #6 

(Scenario 5 + 

SOFA at B253)

0.67 0.79 0.38 0.36 0.23 0.23 1.39 1.76 1.06 1.31 0.78 0.56 

Scenario #7 

(Scenario 6 + 

SNCR at B253) 

0.49 0.59 0.28 0.35 0.18 0.17 1.57 1.96 1.16 1.32 0.83 0.62 

Baseline 

(Boiler 24 

Only)

0.21 0.24 0.15 0.18 0.13 0.07 - - - - - - 

Baseline 

(B-6C 

Furnaces and 

OC-Batch)

0.00 0.01 0.00 0.00 0.00 0.00 - - - - - - 

Table 8.3.1.4 TVA-Cumberland BART Evaluation Visibility Impacts Summary 

Modeling 

 Scenario 

Modeled Visibility 

Impacts 

(dv) 

Visibility Improvement 

(delta -dv) 

 Mammoth 

Cave 

Sipsey Mammoth 

Cave 

Sipsey 

Baseline 

(Two Coal-fired Boilers with 

Hydrated Lime Injection) 

 (Per Unit CUF) 

0.712 0.287 -- -- 

Scenario #1 

(PM10 Control on Boilers w. 

Wet ESP) 

(Per Unit CUF) 

0.240 0.095 0.472 0.192 

Table 8.3.1.5 DuPont-Old Hickory BART Evaluation Visibility Impacts Summary 

 @ Daily Maxi,um Rates (Old Improve Equation) 
84 

Modeling 

 Scenario 

Modeled Visibility 

Impacts 

(dv) 

Visibility Improvement 

(delta -dv) 

Mammoth Cave Mammoth Cave 

SO2 Cases (9 scenarios) 

A. Baseline Case Using Current Coal 0.929 (*) - 

F. 1.5% Sulfur Coal with No Scrubbing 0.792 0.137 

K. 1.0% Coal with No Scrubbing 0.599 0.330 

E. Current Coal with Sodium Wet Scrubber 

on Boiler 20 Only 

0.439 0.490 

J. 1.5% Sulfur Coal with Sodium Wet 

Scrubber on Boiler 20 Only

0.398 0.531 

O. 1.0% Sulfur Coal with Sodium Wet 

Scrubber on Boiler 20 Only

0.332 0.597 

C. Current Coal with Sodium Wet Scrubber 

on both Boilers 20 & 24

0.305 0.624 

H. 1.5% Sulfur Coal with Sodium Wet 

Scrubber on Both Boilers 20 & 24

0.291 0.638 

M. 1.0% Sulfur Coal with Sodium Wet 

Scrubber on Both Boilers 20 & 24

0.272 0.657 

P. Current Coal with 50% Natural Gas Cofiring on Both Boilers 20 & 240.605 0.324 

NOx Cases (7 Scenarios) 

A. Baseline Case Using Current Coal 0.929 (*) - 

D1. LNB on Boiler 20 only 0.917 0.012 

D2. SNCR on Boiler 20 only 0.917 0.012 

B1. LNB on Both Boilers 20 & 24 0.917 0.012 

B2. SNCR on Both Boilers 20 & 24 0.917 0.012 

E. LNB Plus SCR on Boiler 20 Only 0.902 0.027 

C. LNB Plus SCR on Both Boilers 20 & 24 0.890 0.039 

B3. Current Coal with 50% Natural Gas Cofiring on Both Boilers 20 & 24 0.605 0.324 

(*) Eighth-highest impact was later reduced to 0.507 dv based on New 

Improve Equation 
85

Table 8.3.1.6 – DuPont-Old Hickory – MACA Visibility Assessment 

Summary of the Control Scenario Visibility & Cost Impacts @ Daily 

Maximum 

 Emission Rate and Highest Day Coal Quality (Old Improve Equation) 

Case Description Expected 

Emission 

rate

Expected 

Emission 

Rate

Total Annualized 

cost of control

Tons 

Removed

Average cost 

Effectiveness

Greatest 

Change in 

Modelled 

98 % day 

from 

baseline

% 

Change in 

Light 

extinction

% of 31.37 

dV (the 

starting 

point for the 

Mammoth 

Cave Glide 

Path)

Incremental %

Improvement 

of % visibility 

Impact as a %

of 31.17 dV

SO2 Cases T/yr lb/hr $ t/yr $/ton removed dV % % %

A. Baseline Case Using Current Coal

7,040 1,607 0.929 9.29 2.96

F. 1.5% Sulfur Coal with No Scrubbing

5,617 1,282 $1,970,962 1,423 $1,385 -0.15 1.5 2.50 0.46

K. 1.0% Sulfur Coal with No Scrubbing

3,745 855 $2,956,443 3,295 $897 -0.349 3.49 1.86 1.10

E. Current Coal with Sodium Wet Scrubber on 

Boiler 20 Only 1,690 386 $14,222,449 5,351 $2,658 -0.508 5.08 1.35 1.61

J. 1.5% Sulfur Coal with Sodium Wet 

Scrubber on Boiler 20 Only 1,348 308 $11,196,391 5,692 $1,967 -0.532 5.32 1.27 1.69

O. 1.0% Sulfur Coal with Sodium Wet 

Scrubber on Boiler 20 Only 899 205 $12,211,479 6,142 $1,988 -0.597 5.97 1.07 1.90

C. Current Coal with Sodium Wet Scrubber on 

Both Boilers 20 & 24 352 80 $23,566,812 6,688 $3,524 -0.624 6.24 0.98 1.98

H. 1.5% Sulfur Coal with Sodium Wet 

Scrubber on Both Boilers 20 & 24 281 64 $17,033,708 6,759 $2,520 -0.638 6.38 0.93 2.03

M. 1.0% Sulfur Coal with Sodium Wet 

Scrubber on Both Boilers 20 & 24 187 43 $18,056,198 6,853 $2,635 -0.657 6.57 0.87 2.09

P. Current Coal with 50% Natural Gas Cofiring 

on Both Boilers 3,520 804 $14,190,215 3,520 $4,031 -0.369 3.69 1.80 1.16

NOx Cases

A. Baseline Case Using Current Coal

1,233 282 0.929 9.29 2.96

D1. LNB on Boiler 20 Only

843 192 $572,769 391 $1,466 -0.033 0.33 2.87 0.09

D2. SNCR on Boiler 20 Only

843 192 $821,184 391 $2,102 -0.033 0.33 2.87 0.09

B1. LNB on Both Boilers 20 & 24

740 169 $963,413 493 $1,953 -0.055 0.55 2.80 0.16

B2. SNCR on Both Boilers 20 & 24

740 169 $1,105,732 493 $2,241 -0.055 0.55 2.80 0.16

E. LNB Plus SCR on Boiler 20 Only

374 85 $2,904,607 859 $3,380 -0.13 1.3 2.56 0.40

C. LNB Plus SCR on Both Boilers 20 & 24

148 34 $5,081,539 1,085 $4,682 -0.178 1.78 2.41 0.55

B3 Current Coal with 50% Natural Gas 

Cofiring on Both Boilers 740 169 $14,190,215 493 $28,759 -0.369 3.69 1.80 1.16
86

8.3.2 Costs of Compliance 

For Alcoa visibility improvement ranged from 0.267 dv at JOKI to 0.712 dv at GRSM at 

costs ranging from $6,697/ton to $8,274/ton (vendor estimate range). The costs for the 

(Wet Scrubber scenario 1)are summarized in Table 8-3.2.1 below taken from the Alcoa 

BART determination permit application submittal (Appendix L-8). The facility proposed 

that BART is taking a pollution prevention limit of 3% sulfur in the calcined petroleum 

coke used to manufacture anodes. 

Table 8.3.2.1 Alcoa - Summary of the Impacts Analysis for SO2 Control Scenarios 

Control 

Scenario 

Control 

Technology 

Evaluated 

Emission 

Rate 

(tons/year) 

Emissions 

Reductions 

(tons/year) 

Installed 

Capital 

Cost 

($000) 

Total 

Annualized 

Control 

Costs 

($000) 

Incremental 

Cost 

Effectiveness 

($ per ton of 

pollutant 

removed) 

Energy 

Impact (000 

kWhour/year) 

Collateral 

Increase 

in other 

Pollutants 

Non-Air 

Quality 

Environmental 

Impacts 

1 3.5% Sulfur 

Coke with 

Potlines 

Wet 

Scrubber 

1,202 5,234a 

$217,000 

$39,000 $7,500 33,200 438 

tons/year 

of PM2.5 

17,600 

tons/year of 

solid waste for 

disposal 180 

million 

gallons/year 

makeup water 

usage 

2 3.0% Sulfur 

Coke with 

Anode Bake 

Furnace 

Wet 

Scrubber 

4,830 687b 30,400 5,600 8,200 2,800 36 

tons/year 

of PM2.5 

2,300 tons/year 

of solid waste 

for disposalc 

3 3.0 % 

Sulfur Coke 

Potlines 

5,517 919 

and Anode 

Bake 

Furnace 

Current None 6,436 Potential 

Emissions 

a

Compared with potential emissions since 3.5% sulfur coke could be used. 

b

Compared with 3.0% sulfur coke emissions since this scenario would only occur with Control Scenario 3. 
87

For Eastman Chemical visibility improvement resulting from control scenarios 

considered ranged from 0.41 dv to 1.96 dv with costs ranging from $1,649/ton of SO2 

removed or $89,000/ton/dv to $2,085/ton of pollutant removed or $110,294/ton/dv, 

respectively. The costs for each of the scenarios considered are summarized in Tables 

8.3.2.2 and 8.3.2.3 below taken from the Eastman BART determination permit 

application submittal (Appendix L-8). The facility proposed that BART is the application 

of Spray Dryer Absorber with Fabric Filtration (SDA/FF) which is a dry flue-gas 

desulfurization using a SDA followed by a fabric filter (scenario 2 in the demonstration) 

for the five Coal-fired Boilers #25-#29 (powerhouse B-253). 

Table 8.3.2.2 – SO2 Costs Effectiveness Summary (5 Boilers) 

Technology Capital 

Cost 

$M 

Annual O/M 

Cost 

$M 

Assumed 

Percent 

Control 

Efficiency 

Annual 

SO2 

Reduced 

(tons) 

CostEffectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

SDA/ESP $97.8 M $6.1 M 71% 10,815 $1,649 -- 

SDA/ESP-FF 

Conversion 

$139.1 M $7.9 M 92% 13,930 $1765 $2,185 (vs. 

SDA/ESP) 

Caustic 

scrubbers 

$87.8 $8.1 M 95% 14,385 $1,295 $410 vs. 

SDA/ESP 

Dual alkali* $106.8 M $7.1 95% 14,385 $1,009 $857 (vs. 

SDA/ESP) 

LSFO $185.8 M $7.7 M 95% 14,385 $2,085 $3,533 vs 

SDA/ESP or 

$12,775 (vs. 

SDA/ESP-FF 

Conversion) 

*Dual alkali provided for information. Its large footprint either eliminates it as an option or drives up 

cost considerably to relocate buildings, railroad tracks, ash ponds, etc. Also, its use has been 

extremely limited and Eastman's confidence that it can be successfully operated is low. 

Table 8.3.2.3 Cost-effectiveness Comparison, B-253 SO2 Options 

Scenario Annualized 

Cost 

Average Dv-yr Change in 

Average 

Dv-yr 

Average CostEffectiveness 

$/dv-yr 

Incremental 

CostEffectiveness 

$/dv-yr 

Baseline N/A 401 -- -- 

Scenario 1 

(SDA/ESP) 

$17.8 M 201 200 $89,000 -- 

Scenario 2 

(SDA/FF) 

$24.6 M 138 263 $93,536 $107,936 (vs. 

Scenario 1) 

Scenario 3a 

(Caustic 

Scrubbing) 

$18.6 M 129 272 $68,382 $11,111 (vs. 

Scenario 1) 

Scenario 3b 

(LSFO) 

$30.0 M 129 272 $110,294 $169,444 (vs. 

Scenario 1) 
88

For TVA-Cumberland visibility improvement resulting from the control scenario 

considered of Wet ESP for both boilers ranged from 0.192 dv at SIPS to 0.472 dv at 

MACA with costs at over $85,000/ton of SO2 removed for each boiler The costs for the 

Wet ESP are summarized in Tables 8.3.2.4 and 8.3.2.5 below taken from the TVACumberland BART determination permit application submittal (Appendix L-8). The 

facility proposed that BART is no additional controls. 

Table 8.3.2.4 Capital Costs for Wet ESP: CUF Unit 1 or 2 

 

 

 Direct Costs Basis Cost 

 Purchased Equipment Costs (PEC) 

 ESP+auxiliary equipment (ESP) $69,700,000 

 Instrumentation 0.10 ESP $6,970,000 

 Sales taxes 0.03 ESP $2,091,000 

 Freight Included -- 

 PEC $78,761,000 

 

 Direct Installation Costs (DIC) 

 Foundations & supports 0.04 PEC $3,150,440 

 Handling & erection 0.50 PEC $39,380,500 

 Electrical 0.08 PEC $6,300,880 

 Piping 0.01 PEC $787,610 

 Insulation for ductwork 0.02 PEC $1,575,220 

 Painting 0.02 PEC $1,575,220 

 DIC $52,769,870 

 

 Total Direct Costs (DC) $131,530,870 

 Indirect Costs 

 Engineering 0.20 PEC $15,752,200 

 Construction and field expenses 0.20 PEC $15,752,200 

 Contractor fees 0.10 PEC $7,876,100 

 Start-up 0.01 PEC $787,610 

 Performance test 0.01 PEC $787,610 

 Model study 0.02 PEC $1,575,220 

 Contingencies 0.03 PEC $2,362,830 

 Total Indirect Costs (IC) $44,893,770 

 

 

Total Capital Investment 

(TCI)=DC+IC $176,424,640

 

 

*Wet ESP equipment costs based on vendor estimate. Other costs are based on information 

 from the EPA Air Pollution Control Cost Manual, Sixth Ed. 

Table 8.3.2.5 Annual Costs for Wet ESP: CUF Unit 1 or 2 
89

 

 

Direct Annual Costs 

(DC) Bases & Assumptions 

 

Operating Labor 

 Operator $ 32,850 2 hrs/shift, 365 days/yr, $15/hr 

 Supervisor $ 4,928 15% of operator labor 

 Coordinator $ 10,950 1/3 of operator labor 

Maintenance 

 Labor $ 69,063 SCA=103 ft2/1000 cfm, 4.5 million cfm 

 Material $ 787,610 1% of PEC 

Utilities 

 Electricity-fan $ 599,342 2" H2O ∆p, $0.06/kWh 

 

Electricityoperating $ 330,830 capacity factor (CF)=0.7 

 Water $ 1,655,640 5 gal/min per 1000 cfm, $0.2/1000 gal, CF=0.7 

Waste Disposal $ 16,556,400 $2/1000 gal 

Total DC $ 20,047,613 

 

Indirect Annual Costs 

(IC) 

 Overhead $ 543,241 60% of operating labor and materials 

 Administrative charge $ 3,528,493 2% of TCI 

 

Payment in lieu of 

taxes $ 1,764,246 1% of TCI 

 Insurance $ 1,002,169 1% of TCI 

 Capital recovery $ 23,619,516 CRF = 0.1339 

 Total IC $ 30,457,664 

 

Total Annual Cost $ 50,505,277 

 

 

*Based on information from the EPA Air Pollution Control Cost Manual, Sixth Ed. Capital recovery 

factor (CRF) based on 12% interest rate and 20-yr equipment life. 

ForDuPont-Old Hickory visibility improvement resulting from the nine (9) control 

scenarios considered of SO2 reductions ranged from 0.137 dv to 0.657 dv at MACA and 

for NOx reductions (7 scenarios) ranged from 0.012 dv to 0.324 dv at MACA too. Table 

8.3.1.6 (above) outlined the control scenarios for reducing SO2 and NOx emissions. The 

economic analyses for Boilers 20 and 24 are addressed in Tables 8.3.2.6, 8.3.2.7, and 

8.3.2.8. The costs for the most practical controls are summarized in Table 8.3.2.9 below 

taken from the DuPont-Old Hickory additional submittal letter dated January, 24, 2008. 

This letter addresses revised cost effectiveness/visibility improvement on feasible controls 

and a proposed BART control determination for the two boilers. This additional 

information is a compliment to their BART determination permit application submittal 

(Appendix L-8). The facility proposed that BART is taking emission limitations as total 

combined daily emissions for Boilers 20 and 24 based upon the following operating 

limits stated in Table 8.3.2.10 below. 
Table 8.3.2.6 BART Economic Analysis for DuPont Old Hickory Boilers 20 & 24 at Maximum Combined Da

BART For SO2 and NOx for Both Boilers 20 & 24 Based on Maximum Emissions Day for 2005-06

SO2 Model Case Identifier--> A F K MH C P O 

Boilers 20 & 24 Boilers 20 & 

SO2 ECONOMIC PARAMETERS BASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 using Coa

FACTORED ESTIMATE FROM RTP DATABASE Current Coal 1 Coal 2 Coal 3 using Coal 3 using Coal 2 using current Coal using current Coal Boiler 20 On

Control Option --> No FGD No FGD No FGD 95% WSS 95% WSS 95% WSS 50% Gas Cofiring 95% WS

Coal Percent Sulfur--> 1.88 1.50 1.00 1.00 1.50 1.88 1.88 1.00 

A&E Emission Rate, lb/MMBtu --> 3.13 2.49 1.66 0.08 0.12 0.16 3.13 0.08 

SO2 Emission Rate at DHI, lb/hr--> 2,375 1,895 1,264 63 95 119 1188 561 

Annual SO2 Emissions, TPY--> 7,040 5,617 3,745 187 281 352 3520 899 

Equivalent Annual Average Hourly SO2 Emissions, lb/hr--> 1,607 1,282 855 43 64 80 804 205 

A&E Total Capital Requirement: $63,365,423 $63,365,423 $63,365,423 $35,425,1

O&M Costs @ 8% + reagent + waste disposal: $7,778,324 $7,741,314 $16,245,380 $5,001,29

Range: +50/-30 +50/-30 +50/-30 +50/-30 

Coal Change Incremental Cost Per Ton vs Baseline: $0 $10 $15 $15 $10 $0 $0 $15 

Coal Change Annual Additional Cost : $1,970,962 $2,956,443 $2,956,443 $1,970,962 $0 $2,956,44

Natural Gas Cofiring Incremental Cost Increase: $14,190,215

Capital Recovery Costs: $6,957,183 $6,957,183 $6,957,183 $3,889,49

Total Annual Costs Excluding Coal Change: $14,735,506 $14,698,497 $23,202,562 $8,890,78

Annual Emissions Reduction vs Baseline Current Coal: 1,423 3,295 6,853 6,759 6,688 3,520 6,142 

Annual Emissions Reduction vs Coal 2: 1,872 5,430 5,336 5,265 2,097 4,718 Annual Emissions Reduction vs Coal 3: 3,558 3,464 3,393 225 2,846 

Downtime at Gas Fuel Price Difference: $3,317,550 $3,317,550 $3,317,550 $3,317,55

Amotized Downtime at Gas Fuel Price Difference: $364,249 $364,249 $364,249 $364,249 

Total Annualized Cost: $1,970,962 $2,956,443 $18,056,198 $17,033,708 $23,566,812 $14,190,215 $12,211,4

Cost Effectiveness Relative to Baseline Current Coal, $/Ton Removed: $1,385 $897 $2,635 $2,520 $3,524 $4,031 $1,988 

Cost Effectiveness Relative to Coal 2, $/Ton Removed: $526 $2,962 $2,823 $4,102 $5,827 $2,170 Cost Effectiveness Relative to Coal 3, $/Ton Removed: $4,244 $4,064 $6,075 $49,997 $3,252 

NOx Model Case Identifier--> A B1 B2 C B D1 D2 E

NOx ECONOMIC PARAMETERS BASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boiler 24 As-Is & Boiler 24 As-Is & Boiler 24 As

FACTORED ESTIMATE FROM RTP DATABASE using current Coal Boiler 20 Only w/ Boiler 20 Only w/ Boiler 20 On

Control Option --> CC LNB SNCR LNB+SCR 50% Gas Cofiring LNB SNCR LNB+SC

NOx Emission Rate at DHI, lb/hr--> 421 252 252 50 252 324 324 208

Annual NOx Emissions, TPY--> 1233 740 740 148 740 843 843 374

Equivalent Annual Average Hourly NOx Emissions, lb/hr--> 282 169 169 34 169 192 192 85

A&E Total Capital Requirement: $5,215,728 $3,122,793 $31,225,760 $2,607,864 $1,856,689 $17,355,3

O&M Costs: $208,629 $580,742 $1,470,994 $104,315 $435,205 $816,962

Range: +50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-30

Natural Gas Cofiring Incremental Cost Increase: $14,190,215

Capital Recovery Costs: $572,659 $342,866 $3,428,421 $286,329 $203,854 $1,905,52

Total Annual Costs Excluding Downtime Gas Cost: $781,288 $923,608 $4,899,414 $390,644 $639,059 $2,722,48

Annual Emissions Reduction: 493 493 1,085 493 391 391 859

Downtime at Gas Fuel Price Difference: $1,658,775 $1,658,775 $1,658,775 $1,658,775 $1,658,775 $1,658,77

Amotized Downtime at Gas Fuel Price Difference: $182,125 $182,125 $182,125 $182,125 $182,125 $182,125

Total Annualized Cost: $963,413 $1,105,732 $5,081,539 $14,190,215 $572,769 $821,184 $2,904,60

Cost Effectiveness Relative to Baseline Current Equipment, $/Ton Removed: $1,953 $2,241 $4,682 $28,762 $1,466 $2,102 $3,380

Incremental Cost Effectiveness Relative to LNB on Boiler 20 Only, $/Ton Removed: $3,803 $5,189 $6,490 $132,585 $4,974

A

Ca
Table 8.3.2.7 BART Economic Analysis for DuPont Old Hickory Boiler 20 at Combined Maximum Daily Emi

SO2 Model Case Identifier--> A FKM H CP O J E

CF as annual 

operating rate= 80%

BASES --->

CF as annual

average % of 

max daily 

emissions=

92% Coal HHV, Btu/lb As-Received= 11,428 Per Boiler MMBtu/hr = 445 Per Boiler SCFM 

=

107,453

Natural Gas Price 

Differential Over Coal, 

$/MMBtu=

$6.00

SO2 ECONOMIC PARAMETERS BASELINE+ Coal 2 Coal 3 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20

FACTORED ESTIMATE FROM RTP DATABASE Current Coal 1 using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using current Co

Control Option --> No FGD No FGD No FGD 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 50% Gas Cofirin

Coal Percent Sulfur--> 1.88 1.50 1.00 1.00 1.00 1.50 1.50 1.88 1.88 1.88

A&E Emission Rate, lb/MMBtu --> 3.13 2.49 1.66 0.25 0.08 0.37 0.12 0.47 0.16 3.13

SO2 Emission Rate at DHI, lb/hr--> 1391 1110 740 111 37 166 55 209 70 695

Annual SO2 Emissions, TPY--> 5632 4494 2996 449 150 674 225 845 282 2816

Equivalent Annual Average Hourly SO2 Emissions, lb/hr--> 1286 1026 684 103 34 154 51 193 64 643

A&E Total Capital Requirement: $52,388,658 $35,425,148 $52,388,658 $35,425,148 $52,388,658 $35,425,148

O&M Costs @ 8% + reagent + waste disposal: $5,057,064 $5,001,297 $5,019,522 $4,971,689 $10,010,512 $9,968,709

Range: +50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-30

Coal Change Incremental Cost Per Ton vs Baseline: $0 $10 $15 $15 $15 $10 $10 $0 $0 $0

Coal Change Annual Additional Cost : $0 $1,576,779 $2,365,168 $2,365,168 $2,365,168 $1,576,779 $1,576,779 $0 $0

Natural Gas Cofiring Incremental Cost Increase: $11,352,241

Capital Recovery Costs: $5,751,993 $3,889,491 $5,751,993 $3,889,491 $5,751,993 $3,889,491

Total Annual Costs Excluding Coal Change: $10,809,057 $8,890,788 $10,771,515 $8,861,180 $15,762,505 $13,858,200

Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3: $4,245 $3,124 $4,639 $3,198 $7,328 $5,106

Annual Emissions Reduction vs Baseline Current Coal: 1,138 2,636 5,183 5,482 4,958 5,408 4,787 5,351 2,816

Annual Emissions Reduction vs Coal 2: 1,498 4,044 4,344 3,820 4,269 3,649 4,212 1,678Annual Emissions Reduction vs Coal 3: 2,546 2,846 2,322 2,771 2,151 2,714 180

8 Weeks Downtime at Gas Fuel Price Difference: $3,317,550 $3,317,550 $3,317,550 $3,317,550 $3,317,550 $3,317,550

Amotized Downtime at Gas Fuel Price Difference: $364,249 $364,249 $364,249 $364,249 $364,249 $364,249

Cost Effectiveness Relative to Baseline Current Coal: $1,385 $897 $2,612 $2,120 $2,564 $1,998 $3,369 $2,658 $4,031

Cost Effectiveness Relative to Coal 2: $526 $2,958 $2,312 $2,915 $2,161 $3,987 $3,002 $5,827Cost Effectiveness Relative to Coal 3: $4,388 $3,252 $4,457 $3,045 $6,398 $4,369 $49,997

NOx Model Case Identifier--> A BBC B DD E

NOx ECONOMIC PARAMETERS BASELINE+ Boiler 20 Boiler 20 Boiler 20 Boiler 20

FACTORED ESTIMATE FROM RTP DATABASE using current Coal

Control Option --> CC LNB SNCR LNB+SCR 50% Gas Cofiring

A&E Emission Rate, lb/MMBtu --> 0.542 0.325 0.325 0.065 0.325

NOx Emission Rate at DHI, lb/hr--> 241 145 145 29 145

Annual NOx Emissions, TPY--> 977 586 586 117 586

Equivalent Annual Average Hourly NOx Emissions, lb/hr--> 223 134 134 27 134

A&E Total Capital Requirement: $2,607,864 $1,856,689 $17,355,321

O&M Costs: $104,315 $435,205 $816,962

Range: +50/-30 +50/-30 +50/-30

Natural Gas Cofiring Incremental Cost Increase: $11,352,241

Capital Recovery Costs: $286,329 $203,854 $1,905,521

Total Annual Costs: $390,644 $639,059 $2,722,483

Cost Effectiveness w/o Gas Cost: $1,000 $1,636 $3,168

Annual Emissions Reduction: 391 391 859 391

4 Weeks Downtime at Gas Fuel Price Difference: $1,658,775 $1,658,775 $1,658,775

Amotized Downtime at Gas Fuel Price Difference: $182,125 $182,125 $182,125

Overall Cost Effectiveness: $1,466 $2,102 $3,380 $29,059

ESTIMATE USING USEPA REFERENCES LOW LNB SNCR LNB+SCR

Emission Rate, lb/MMBtu --> 0.54 0.325 0.325 0.065

Total Capital Requirement: $400,500 $1,112,500 $2,562,142

O&M Costs: $44,500 $222,500 $199,674

Range: LOW HIGH NA

Capital Recovery Costs: $43,973 $122,147 $281,309

Total Annual Costs: $88,473 $344,647 $480,983 Annualinterestrate (fractional): 0.07

Cost Effectiveness: $226 $882 $560 C ontrolsystem life (years): 15

Annual Emissions Reduction: 391 391 859 C apitalrecovery factor(system ): 0.110

BART FOR SO2 & NOX BOILER # 20 BASED ON MAXIMUM EMISSIONS DAY FOR 2005-06
Table 8.3.2.8 BART Economic Analysis for DuPont Old Hickory Boiler 24 at Maximum Combine

SO2 Model Case Identifier--> A FKM H CP O J E

CF as annual 

operating rate= 20%

BASES --->

CF as annual

average % of 

max daily 

emissions=

33% Coal HHV, Btu/lb As-Received= 11,428 Per Boiler MMBtu/hr = 315 Per Boiler SCFM 

=

81,478

Natural Gas Price 

Differential Over Coal, 

$/MMBtu=

$6.00

SO2 ECONOMIC PARAMETERS BASELINE+ Coal 2 Coal 3 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24

FACTORED ESTIMATE FROM RTP DATABASE Current Coal 1 using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using current Coal

Control Option --> No FGD No FGD No FGD 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 85% SDA+FF 95% WSS 50% Gas Cofiring

Coal Percent Sulfur--> 1.88 1.50 1.00 1.00 1.00 1.50 1.50 1.88 1.88 1.88

A&E Emission Rate, lb/MMBtu --> 3.13 2.49 1.66 0.25 0.08 0.37 0.12 0.469 0.156 3.13

SO2 Emission Rate at DHI, lb/hr--> 985 786 524 79 26 118 39 148 49 492

Annual SO2 Emissions, TPY--> 1408 1123 749 112 37 169 56 211 70 704

Equivalent Annual Average Hourly SO2 Emissions, lb/hr--> 321 256 171 26 9 38 13 48 16 161

A&E Total Capital Requirement: $41,319,616 $27,940,275 $41,319,616 $27,940,275 $41,319,616 $27,940,275

O&M Costs @ 8% + reagent + waste disposal: $3,522,056 $2,777,027 $3,512,670 $2,769,625 $7,018,208 $6,276,670

Range: +50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-30

Coal Change Incremental Cost Per Ton vs Baseline: $0 $10 $15 $15 $15 $10 $10 $0 $0 $0

Coal Change Annual Additional Cost : $0 $394,183 $591,274 $591,274 $591,274 $394,183 $394,183 $0 $0

Natural Gas Cofiring Incremental Cost Increase: $2,837,974

Capital Recovery Costs: $4,536,672 $3,067,692 $4,536,672 $3,067,692 $4,536,672 $3,067,692

Total Annual Costs Excluding Coal Change: $8,058,727 $5,844,719 $8,049,342 $5,837,317 $11,554,880 $9,344,362

Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3: $12,659 $8,215 $13,868 $8,426 $21,488 $13,771

Annual Emissions Reduction vs Baseline Current Coal: 285 659 1,296 1,371 1,240 1,352 1,197 1,338 704

Annual Emissions Reduction vs Coal 2: 374 1,011 1,086 955 1,067 912 1,053 419Annual Emissions Reduction vs Coal 3: 637 711 580 693 538 679 45

Downtime at Gas Fuel Price Difference: $0 $0 $0 $0 $0 $0

Amotized Downtime at Gas Fuel Price Difference: $0 $0 $0 $0 $0 $0

Cost Effectiveness Relative to Baseline Current Coal: $1,385 $897 $6,676 $4,696 $6,812 $4,610 $9,655 $6,986 $4,031

Cost Effectiveness Relative to Coal 2: $526 $8,165 $5,563 $8,429 $5,469 $12,235 $8,500 $5,827Cost Effectiveness Relative to Coal 3: $12,659 $8,215 $13,528 $8,141 $20,388 $12,900 $49,997

NOx Model Case Identifier--> A B B C B

NOx ECONOMIC PARAMETERS BASELINE+ Boiler 24 Boiler 24 Boiler 24 Boiler 24

FACTORED ESTIMATE FROM RTP DATABASE using current Coal

Control Option --> CC LNB SNCR LNB+SCR 50% Gas Cofiring

A&E Emission Rate, lb/MMBtu --> 0.57 0.342 0.342 0.068 0.342

NOx Emission Rate at DHI, lb/hr--> 180 108 108 22 108

Annual NOx Emissions, TPY--> 257 154 154 31 154

Equivalent Annual Average Hourly NOx Emissions, lb/hr--> 59 35 35 7 35

A&E Total Capital Requirement: $2,607,864 $1,266,104 $13,870,439

O&M Costs: $104,315 $145,537 $654,032

Range: +50/-30 +50/-30 +50/-30

Natural Gas Cofiring Incremental Cost Increase: $2,837,974

Capital Recovery Costs: $286,329 $139,011 $1,522,900

Total Annual Costs: $390,644 $284,548 $2,176,931

Cost Effectiveness w/o Gas Cost: $3,803 $2,770 $9,634

Annual Emissions Reduction: 103 103 226 103

Downtime at Gas Fuel Price Difference: $0 $0 $0

Amotized Downtime at Gas Fuel Price Difference: $0 $0 $0

Overall Cost Effectiveness: $3,803 $2,770 $9,634 $27,632

ESTIMATE USING USEPA REFERENCES LOW LNB SNCR LNB+SCR

Emission Rate, lb/MMBtu --> 0.57 0.342 0.342 0.068

Total Capital Requirement: $283,500 $787,500 $2,063,784

O&M Costs: $31,500 $157,500 $157,419

Range: LOW HIGH NA

Capital Recovery Costs: $31,127 $86,463 $226,592

Total Annual Costs: $62,627 $243,963 $384,011 Annualinterestrate (fractional): 0.07

Cost Effectiveness: $610 $2,375 $1,699 C ontrolsystem life (years): 15

Annual Emissions Reduction: 103 103 226 C apitalrecovery factor(system ): 0.110

BART FOR SO2 & NOX BOILER # 24 BASED ON MAXIMUM EMISSIONS DAY FOR 2005-06

94

Table 8.3.2.9 DuPont-Old Hickory BART Control Cost Effectiveness Evaluation 

Summary 

 @ Daily Maxi,um Rates (Old Improve Equation) 

Modeling 

 Scenario 

Total Annualized 

Cost of Control 

Greatest Change in 

dv from baseline 

Cost per dv 

improvement 

SO2 Cases (Most Practical Control Scenarios) 

A. Baseline Case Using Current Coal (0.929 dv at MACA)(*)

F. 1.5% Sulfur Coal with No Scrubbing $1,970,962 -0.15 dv $13,139,746/dv 

K. 1.0% Coal with No Scrubbing 

E. Current Coal with Sodium Wet Scrubber 

on Boiler 20 Only 

$14,222,449 -0.508 dv $27,996,946/dv 

J. 1.5% Sulfur Coal with Sodium Wet 

Scrubber on Boiler 20 Only

 

O. 1.0% Sulfur Coal with Sodium Wet 

Scrubber on Boiler 20 Only

 

C. Current Coal with Sodium Wet Scrubber 

on both Boilers 20 & 24

 

H. 1.5% Sulfur Coal with Sodium Wet 

Scrubber on Both Boilers 20 & 24

 

M. 1.0% Sulfur Coal with Sodium Wet 

Scrubber on Both Boilers 20 & 24

 

P. Current Coal with 50% Natural Gas Cofiring on Both Boilers 20 & 24 

NOx Cases (Most Practical Control Scenarios) 

A. Baseline Case Using Current Coal (0.929 dv at MACA)(*)

D1. LNB on Boiler 20 only $572,769 -0.033 dv $17,356,636/dv 

D2. SNCR on Boiler 20 only $821,184 -0.033 dv $24,884,363/dv 

B1. LNB on Both Boilers 20 & 24 

B2. SNCR on Both Boilers 20 & 24 

E. LNB Plus SCR on Boiler 20 Only 

C. LNB Plus SCR on Both Boilers 20 & 24 

B3. Current Coal with 50% Natural Gas Cofiring on Both Boilers 20 & 24  

(*) Eighth-highest impact was later reduced to 0.507 dv based on New Improve Equation 

Table 8.3.2.10 DuPont-Old Hickory BART Control Determination–Proposed Emission 

Limitations 

Operating Limits SO2 (lb/day) NOx (lb/day) 

Summer Months (May-September) 32260 6120 

NON-Summer Months (October -April) 38570 6770 
95

 

8.3.3 Energy and Non-air Quality Impacts 

For Alcoa, a wet scrubber removes SO2 by forcing the exhaust gas through a spray 

tower or absorber where it contacts water droplets that contain the unreacted lime or 

limestone. Energy is required to overcome the resistance of the scrubber components as 

well as falling water droplets. A substantial amount of energy is associated with a fan to 

move approximately 2,000,000 acfm through the scrubber. The fan alone would require 

1,730–1,960 kW. Other energy is required for the slurry pumps, instrumentation, and 

miscellaneous items (e.g., lighting). The total energy required, based on an average of 

the two proposals, would be approximately 3,800 kW. As listed in Table 8.3.2.1, this is 

equivalent to 33,200,000 kW-hours of electricity per year. A wet scrubber on the anode 

bake furnace would add 2,800,000 kW-hours per year. For non-air quality impacts, both 

of the wet scrubber proposals were based on the Limestone Slurry Forces Oxidation 

(LSFO) process. 

This process oxidizes the spent slurry to gypsum, which may be landfilled or 

commercially sold. There is no way to know at this time whether the gypsum would have 

commercial value or whether there would be any demand for it. Therefore, it must be 

assumed that 17,600 tons of waste from the potlines wet scrubber and 2,300 tons of waste 

from the anode bake furnace wet scrubber would be landfilled each year. It is estimated 

that 180 million gallons of water will be required annually to operate the potline wet 

scrubber at a cost of $270,000. This will significantly impact the community 

infrastructure in that this will increase daily water demand by approximately 4%. There 

will be relatively no impact due to water discharge, at approximately 4 gallons/minute. It 

is also estimated that 36 million kWh would be needed to operate the scrubbers annually. 

This would impact power demand in the community and therefore also have an 

environmental impact due to power production equivalent to adding over 3,000 new 

households in the community. 

For Eastman Chemical, the cost estimates include any changes, positive or negative, on 

energy consumption. For non-air quality environmental impacts, the cost estimates 

include any changes, positive or negative, on solid waste disposal and wastewater 

treatment. The Spray Dryer Absorber (SDA) options, the dual alkali, and the LSFO 

options would all generate solid waste streams that would be disposed at Eastman's onsite nonhazardous waste landfill. Eastman has estimated this additional waste would 

shorten the landfill life by about 5 years (15 percent reduction in remaining life). Since 

the SDAs would be placed before the particulate removal devices, the calcium sulfate 

byproduct would be mixed with the flyash and any sales of flyash to the concrete industry 

would be lost. We have estimated this loss of flyash sales at 11,000 tons per year and 

that this volume would shorten the landfill life by an additional year or two. Loss of this 

volume of flyash to the concrete industry would mean that much more cement would be 

required resulting in consumption of additional energy (natural gas) and raw materials 

to produce the cement along with the associated air emissions. It would also result in an 

increased price of concrete. The loss of landfill space due to either of these reasons 

(calcium sulfate sludge or loss of flyash sales) should not cause a direct environmental 
96

impact as the landfill has liners and leachate collection systems and should have no 

impact on groundwater. 

Any leachate or stormwater runoff collected in the landfill's stormwater basins is 

permitted for discharge to the South Fork Holston River. However, once the landfill is 

full, a new one will have to be sited, likely further from Eastman's facility. Inevitably, a 

new landfill will result in loss of natural habitat and result in other community impacts 

such as noise and scenic concerns. The caustic scrubber option would generate a scrubber 

blowdown stream containing dissolved salts which would require discharge to the South 

Fork Holston River (SFHR) through an NPDES permitted outfall. The salts in this 

blowdown stream would be comprised of sodium sulfate (99.5 %), sodium fluoride (0.4 

%), and sodium chloride (0.06 %). The volume of the discharge is expected to be 

approximately 0.5 MGD. Under normal operating conditions the blowdown would 

increase Eastman's Total Dissolved Solids (TDS) loading to the river by approximately 

238,000 lb/day. 

The worst-case maximum TDS loading could increase by as much as 351,000 lb/day. The 

SFHR immediately downstream of Eastman and the city of Kingsport is classified for use 

as an industrial water supply by the Tennessee Department of Environment and 

Conservation. Due to this classification, an ambient water quality criterion of 500 mg/L

TDS applies in this reach of the river. Based on the three most recent years of quarterly 

data, the current average ambient TDS concentration downstream of Kingsport is 196 

mg/L. Under normal scrubber blowdown discharge conditions and average river flow, 

the discharge of the scrubber blowdown would result in an increase in TDS of 

approximately 17 mg/L downstream of Kingsport. Therefore, due to the blowdown 

discharge, the average TDS concentration downstream of the discharge is projected to 

increase to 213 mg/L (196 + 17). 

This projected value is below the 500 mg/L standard and within the range of values 

currently measured in the river. A worst-case evaluation of the impact of the blowdown 

discharge was performed based on low flow in the river combined with the maximum 

upstream river TDS concentration, the maximum projected increase in loading (351,000 

lb/day) discharged by the scrubber, and the maximum simultaneous discharge of TDS 

from all area point sources. This worst-case analysis resulted in a projected downstream 

concentration of 349 mg/L. The discharge of scrubber blowdown, while increasing the 

level of TDS in the SFHR, would not result in an exceedence of the 500 mg/L water 

quality criterion even under worst-case conditions. 

For TVA-Cumberland, the energy costs associated with a Wet ESP are listed in Table 

8.3.2.5 above. This cost is over $930,000.00 on an annual basis for electricity usage 

alone. 

For the non-air Environmental Impacts, a Wet ESP is a water intensive system. 

 According to the EPA Air Pollution Control Cost Manual, a wet ESP uses at least 5 

gal/min of water per 1,000 cfm of flue gas. Based on this ratio, operating wet ESPs on 
97

both units at CUF would consume over 16 billion gallons per year of additional water 

and require treatment of an equivalent volume of wastewater. 

For DuPont – Old Hickory, this analysis does not provide detailed quantification of 

energy and non-air quality environmental impacts for each compliance option since this 

is a high level analysis. However, those impacts and be described qualitatively. 

Use of lower sulfur alone coal would not entail any significant changes to energy use or 

non-air quality environmental impacts. 

Use of a spray dry scrubber would require use of lime as the reagent. Solid waste 

disposal would increase over the current coal ash-only condition by the quantity of 

calcium sulfite/sulfate formed in the scrubber. This can be estimated based on removal 

percent and expected calcium/sulfur stoichiometric ratio. Costs for that disposal are 

included within the estimated O&M cost estimates. As indicated above, the additional 

waste would be dry, so it would likely be disposed of in a landfill. Additional purchased 

electricity would be required for operation of the scrubber and baghouse, including, for 

example, lime transport, slurry preparation and injection, baghouse pulse air, ash and 

spent sorbent handling, and increased fan power to compensate for increased flue gas 

pressure drop. Increased purchased electricity would result in increased emissions of 

SO2, NOx, CO2, and other emissions from the electric utility generators providing that 

power, which could in fact, be units that themselves impact Class I areas with their SO2

and NOx emissions. Water would also be consumed for slurry preparation. 

Use of a sodium wet scrubber would require use of caustic as the reagent. Liquid waste 

disposal would increase for disposal of the scrubber blowdown stream. The existing 

plant waste water treatment facility likely does not have adequate capacity for that waste 

stream directly, but some form of neutralization and oxidation would be required prior to 

transfer to the waste treatment system. Costs for that disposal are included within the 

estimated O&M cost estimates. Additional purchased electricity would be required for 

operation of the scrubber, including, for example, liquid pumping power and increased 

fan power to compensate for increased flue gas pressure drop. Increased purchased 

electricity would result in increased emissions of SO2, NOx, CO2, and other emissions 

from the electric utility generators providing that power, which could in fact, be units 

that themselves impact Class I areas with their SO2 and NOx emissions. Water would 

also be consumed for the scrubber solution. 

Use of Low NOx Burners (LNB) would result in increased unburned carbon in the flyash 

due to lower flame temperatures. This could impact the method of disposal of flyash in 

that beneficial reuse might not be possible, and landfill disposal might be the only option. 

The associated efficiency loss with increased unburned carbon would result in 

incremental increase in coal consumption and the associated electricity for pulverization 

and fan power, as well as increased ash disposal overall. 

Selective Non Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR) 

technologies would utilize ammonia or urea as reagents. Ammonia slip would occur with 
98

either control technology. Ammonia slip reacts with sulfur and chloride species in the 

flue gas forming ammonium salts which increase the concentration of fine particulates 

(PM2.5) in the flue gas, potentially increasing stack opacity. On-site storage of ammonia 

would create its own set of safety issues. Disposal of spent catalyst would be a long term 

solid waste issue for SCR. 

8.3.4 Existing Control 

For Alcoa, existing controls on the BART subject sources are described in Table 8.1.1.1 

(above). They comprise of primary control system of fluid-bed reactor type system with 

fabric filtration downstream of the reactor beds (Potlines 1 and 2, and Anode Baking 

Furnace). The rest of the BART subject units are controlled by fabric filteration. 

For Eastman Chemical, existing controls on the BART subject sources are described in 

Table 8.1.1.2 (above). There are no existing add-on SO2 controls for the Coal-fired 

Boilers, only sulfur content limitation in the fuel. For NOx control, LNB is applied for the 

ozone season for Boilers #25-#29 only. Cracking furnaces are natural-gas fired only. 

General Purpose Batch Chemical Manufacturing (OC-BATCH) SO2 and NOx emissions 

are controlled by Scrubbers. PM emissions for each boiler are controlled by ESPs. 

For TVA-Cumberland, the facilty has two pulverized-coal-fired steam generators that are 

considered BART eligible. Units 1 and 2 are nominally rated at about 1325 MW each. 

Both units are equipped with flue gas desulfurization (FGD) systems for sulfur dioxide 

(SO2) control, selective catalytic reduction systems for controlling nitrogen oxides (NOx), 

and electrostatic precipitators (ESPs) to control particulate matter (PM) emissions. In 

addition, CUF currently uses hydrated lime injection on both units to mitigate stack 

opacity. 

The two units at CUF are subject to the EPA Clean Air Interstate Rule (CAIR). Based on 

guidance from EPA and TDEC-APC, compliance with CAIR satisfies BART requirements 

for SO2 and NOx emissions at electric generating units. 

For DuPont-Old Hickory, as discussed in Section 8.1.1.3 earlier, the two Industrial 

Boilers #20 and #24 have the following permit limitations: 

• Boilers 20 and 24 are subject to MCL 10.56.200 (Davidson County-Local 

Program) which limits the maximum sulfur content of any solid or liquid fuel to 

2.0% sulfur by weight. The above standards are based on a maximum sulfur 

content of 0.05% by weight for No.2 Fuel Oil. 

• Boilers 20 and 24 are subject to 40 CFR 75, Subpart H, NOx Budget Trading 

Program. 

• All boilers are subject to 40 CFR 63, Subpart DDDDD, Industrial, Commercial, 

and Institutional Boilers and Process Heaters with a compliance date of 

September 13, 2007. 
99

8.3.5 Remaining Useful Life 

For Alcoa, the facility has been in operation since 1913 and it intends to be in operation 

throughout the period of the regional Haze Program. 

For Eastman Chemical, the remaining useful life is not expected to affect the BART 

determination. 

For TVA-Cumberland, the remaining useful life is not expected to affect the BART 

determination. 

For DuPont-Old Hickory, the remaining useful life is not expected to affect the BART 

determination. 

 

8.3.6 Degree of Visibility Improvement 

Already discussed earlier for each facility. 

8.4 Final BART Determination 

After reviewing the proposed BART determinations and considering the factors, TDECAPC permitting staff 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/FFdry flue-gas 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 8.4 below. 

 

Table 8.4 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 
100

TDEC-APC plans to notice draft permits after approval of the Tennessee Regional Haze 

SIP by EPA and issue final permits as expeditiously as possible but no later than five 

years after the date of the SIP approval. The permits will be issued following Tennessee’s 

standard permitting process. The BART specific permit conditions for those sources are 

included as Appendix L-12. 

EPA Findings Tennessee has appropriately addressed this provision. The State 

appropriately documented the technical analysis to assess the need and implementation of 

BART controls as applicable for those non-CAIR EGU emission units of PM, SO2 and 

NOx precursor emissions. This involved identification of existing controls on applicable 

emission units, potential control options for applicable emission precursors, and the 

successful application of the Five Factors to determine the feasibility of controls that 

constituted BART. 

EPA agrees with Tennessee’s analyses and conclusions for BART for Alcoa, Eastman 

Chemical, DuPont–Old Hickory, and the PM assessment for BART for TVA Cumberland 

because the analyses were conducted consistent with EPA’s BART Guidelines and 

EPA’s Air Pollution Control Cost Manual, and the conclusions reflect a reasonable 

application of EPA’s guidance to these sources. 

 
101

 

III. Evaluation of State Regional Haze Submittal 

D. Best Available Retrofit Technology (BART) Requirements

D.5. Enforceability of BART: For each BART-eligible source in the State subject to 

BART, the implementation plan should include emission limitations representing BART 

and schedules for compliance with BART. For each BART-eligible source in the State 

subject to BART, a requirement that each source subject to BART be required to install 

and operate BART as expeditiously as practicable, but in no event later than 5 years after 

approval of the implementation plan revision and a requirement that each source subject 

to BART maintains the control equipment required by this subpart and establishes 

procedures to ensure such equipment is properly operated and maintained. 

State Regional Haze Submittal 

Page 66 

From those determinations, permit conditions have been developed for each BART 

facility. Upon USEPA’s final approval of the Tennessee Regional Haze SIP as 

announced in the Federal Register thereby constituting approval the following BART 

permit conditions, said conditions will be inserted into the facility’s Part 70 Title V 

Operating Permit as a new applicable requirement. The timing of adding these federally 

approved permit conditions will be done consistent with the permit reopening provisions 

of the Tennessee rules that implement Part 70. Any reference to Part 70 or Tennessee’s 

rules that implement Part 70 are merely to explain the vehicle and timing of the permit 

action and not to offer them for inclusion into the Regional Haze SIP. The permit 

conditions listed below will become applicable requirements and are offered for federal 

approval into Tennessee’s Regional Haze SIP. Pursuant to Division Rule 1200-3-23-

.05, actual operating permits for the sources are presented in Appendix L-12. Like the 

aforementioned permit conditions, these permits will become effective upon USEPA’s 

final approval of the Tennessee Regional Haze SIP and serve until such time that they 

can be added to the facilities’ Part 70 permits as a new applicable requirement as 

described above. 

EPA Findings. Rather than adopt a rule Tenessee has chosen to directly adopt BART 

emission limits in its SIP. These limits will become effective upon the EPA’s final 

approval of the submittal. These limits will subsequently be added to the appropriate Part 

70 permits. Tennessee has appropriately addressed this provision. 
102

III. Evaluation of State Regional Haze Submittal 

E. Coordination of Regional Haze and RAVI Requirements 

The State must revise its plan to provide for review and revision of a coordinated longterm strategy for addressing reasonably attributable and regional haze visibility 

impairment.

State Regional Haze Submittal 

Tennessee did not explicitly address this provision. However TDEC has included 

provisions that updated all the provisions: 

Pages 89-90 

Monitoring Strategy 

In addition to the IMPROVE measurements, some ongoing long-term limited monitoring 

supported by Federal Land Managers provides additional insight into progress toward 

regional haze goals. Tennessee benefits from the data from these measurements, but is not 

responsible for the funding decisions to maintain these measurements into the future. Such 

measurements include: 

• Web cameras operated by the National Park Service at Look Rock, TN at the Great 

Smoky Mountains National Park 

• An integrating nephelometer for continuously measuring light scattering, operated by 

the National Park Service at Look Rock, TN. 

• A Tapered Element Oscillating Microbalance (TEOM) for continuously measuring 

PM2.5 mass concentration, operated by the National Park Service at Look Rock, TN. 

In addition, TDEC-APC and the local air agencies in the State operate a fairly 

comprehensive PM2.5 network of the filter based Federal reference method monitors, 

continuous mass monitors (TEOMs) and filter based speciated monitors. A map of the 

various locations around the State is included in Figure 9.0.1. These PM2.5 measurements 

help TDEC-APC characterize air pollution levels in areas across the state, and therefore aid 

in the analysis of visibility improvement in and near the Class I areas. 

The IMPROVE measurements are central to Tennessee’s regional haze monitoring strategy, 

and it is difficult to visualize how the objectives listed above could be met without the 

monitoring provided by IMPROVE. Any reduction in the scope of the IMPROVE network in 

Tennessee would jeopardize the State’s ability to demonstrate reasonable progress toward 

visibility improvement in its Class I areas. 

Data produced by the IMPROVE monitoring network will be used nearly continuously 

for preparing the 5-year progress reports and the 10-year SIP revisions, each of which 

relies on analysis of the preceding five years of data. Consequently, the monitoring data 

from the IMPROVE sites needs to be readily accessible and to be kept up-to-date. 

Presumably, IMPROVE will continue to process information from its own measurements 

at about the same pace and with the same attention to quality as it has shown in the 

recent past. The VIEWS web site has been maintained by VISTAS and the other Regional 

Planning Organizations to provide ready access to the IMPROVE data and data analysis 
103

tools. TN is encouraging VISTAS and the other RPOs to maintain VIEWS or a similar 

data management system to facilitate analysis of the IMPROVE data. 

 

Page 92 

Ten Year Plan and Five Year Plan Update 

40 CFR section 51.308(f) requires TDEC-APC to revise its regional haze 

implementation plan and submit a plan revision to USEPA by July 31, 2018 and every ten 

years thereafter. In accordance with the requirements listed in Section 51.308(f) of the 

federal rule for regional haze, Tennessee commits to revising and submitting this 

regional haze implementation plan by July 31, 2018 and every ten years thereafter.

In addition, Section 51.308(g) requires periodic reports evaluating progress 

towards the reasonable progress goals established for each mandatory Class I area. In 

accordance with the requirements listed in Section 51.308(g) of the federal rule for 

regional haze, TDEC-APC commits to submitting a report on reasonable progress to the 

USEPA every five years following the initial submittal of the SIP. The report will be in 

the form of a SIP revision. The reasonable progress report will evaluate the progress 

made towards the reasonable progress goal for each mandatory Class I area located 

within Tennessee and in each mandatory Class I area located outside Tennessee which 

may be affected by emissions from within Tennessee. 

Page 93 

NSR/PSD 

As mentioned earlier in Section 7.8, Step Three, TDEC-APC will consider 

visibility as part of its NSR/PSD program. TDEC-APC believes that its current new 

source review regulations for both nonattainment areas as well as the prevention of 

significant deterioration will address emissions from new major sources that may be 

located near a Class I area, or increased emissions from major modifications to existing 

sources. In addition, under the TDEC-APC regulations that govern these sources, 

consultation with the FLMs is also required for sources that are subject to the new 

source review regulations. 

Page 93 

Consultation 

TDEC-APC also commits to ongoing consultation with the FLMs throughout the 

implementation process, including annual discussion of the implementation process and 

the most recent IMPROVE monitoring data and VIEWS data. 

EPA Findings: 

Under the RAVI regulations, a State’s RAVI SIP must address any integral vistas 

identified by the FLMs pursuant to 40 CFR 51.304. An integral vista is defined in 40 

CFR 51.301 as a view perceived from within the mandatory Class I Federal area of a 

specific landmark or panorama located outside the boundary of the mandatory Class I 

Federal area. Visibility in any mandatory Class I Federal area includes any integral vista 

associated with that area. Tennessee does not have any integral vistas identified by the 

FLMs, none of its Class I areas are experiencing RAVI, nor are any of its sources 
104

affected by the RAVI provisions. Thus, the April 4, 2008, Tennessee regional haze SIP 

submittal does not explicitly address the two provisions regarding coordination of 

regional haze and RAVI long-term strategies and monitoring requirements. However the 

State’s previous commitment to address RAVI should the FLM certify visibility 

impairment from an individual source remains unchanged as do the previously approved 

PSD/NSR visibility provisions (July 18, 1996 at 61 FR 35387). EPA finds that this 

regional haze submittal appropriately supplements and augments Tennessee’s RAVI 

visibility provisions to address regional haze, updating the monitoring and LTS 

provisions as summarized below in this section. 

 In the April 4, 2008, submittal, TDEC updated its monitoring program 

commitments and developed a LTS to address Regional Haze. TDEC also commits to 

review and revise its regional haze implementation plan and submit a plan revision to 

EPA by July 31, 2018, and every ten years thereafter, as required by the RHR. In 

accordance with the requirements listed in 51.308(g) of the federal rule for regional haze, 

TDEC commits to submitting a report on reasonable progress to EPA every five years 

following the initial submittal of the SIP, as required by the RHR. The report will be in 

the form of a SIP revision. The reasonable progress report will evaluate the progress 

made towards the reasonable progress goal for each mandatory Class I area located 

within Tennessee and in each mandatory Class I area located outside Tennessee which 

may be affected by emissions from within Tennessee. In addition, consistent with the 

monitoring provisions for RAVI and regional haze under 40 CFR 51.305 and 40 CFR 

51.308(d)(4), Tennessee will rely on the IMPROVE network for complying with the 

regional haze monitoring requirement in the RHR. Finally, the Tennessee NSR rules, 

which were approved in 1996, continue to provide a framework for review and 

coordination with the FLM on new sources which may have an adverse impact on 

visibility in either form (i.e., RAVI and/or regional haze) in any Federal Class I area. 

Although Tennessee submitted and EPA approved visibility rules addressing NSR (July 

18, 1996, at 61 FR 35387, 40 CFR 52.2239 (c)(138)) and a plan addressing monitoring 

and reporting (July 2, 1997, at 62 FR 35681, 40 CFR 52.2239(c)(147)), the EPA 

approvals of these rules neglected to remove the federally promulgated provisions in 40 

CFR 52.2234. EPA corrected this omission in a separate rulemaking (April 21, 2010, 75 

FR 20783).
105

III. Evaluation of State Regional Haze Submittal 

F. Monitoring Strategy and Other Implementation Requirements

Monitoring Strategy: The plan must include a monitoring strategy for measuring, 

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

of all mandatory Class I Federal areas within the State and/or summarize monitoring 

strategy of States with affected mandatory Class I Federal areas. Compliance with this 

requirement may be met through participation in the Interagency Monitoring of Protected 

Visual Environments (IMPROVE) network. 

Other Requirements: The implementation plan must also provide for the following: 

A. The establishment of any additional monitoring sites or equipment needed to 

assess whether reasonable progress goals to address regional haze for all 

mandatory Class I Federal areas within the State are being achieved. 

B. Procedures by which monitoring data and other information are used in 

determining the contribution of emissions from within the State to regional haze 

visibility impairment at mandatory Class I Federal areas both within and outside 

the State. 

C. The reporting of all visibility monitoring data at least annually for each mandatory 

Class I Federal area in the State. To the extent possible, the State should report 

monitoring data for visibility electronically and use of the Visibility Information 

Exchange Web System (VIEWS) is encouraged. 

D. Other elements, including reporting, recordkeeping, and other measures, 

necessary to assess and report on visibility. 

 

State Regional Haze Submittal 

Page 88- 90 

The primary monitoring network for regional haze, both nationwide and in Tennessee, is 

the IMPROVE network. Given that IMPROVE monitoring data from 2000-2004 serve as 

the baseline for the regional haze program, the future regional haze monitoring strategy 

must necessarily be based on, or directly comparable to, IMPROVE. The IMPROVE 

measurements provide the only long-term record available for tracking visibility 

improvement or degradation and therefore Tennessee intends to rely on the IMPROVE 

network for complying with the regional haze monitoring requirement in the Regional 

Haze Rule. 

There is currently 1 IMPROVE site in the State. As Table 1 shows, an IMPROVE site in 

the Great Smoky Mountains National Park in Tennessee serves as the monitoring site for 

both the Great Smoky Mountains National Park and Joyce Kilmer – Slickrock Wilderness 

Area, both of which lie partly in Tennessee and partly in North Carolina. 

Class I Area IMPROVE Site Designation

Great Smoky Mountains National Park GRSM1 (TN)

Joyce Kilmer – Slickrock Wilderness 

Area

GRSM1 (TN)

Table 1. Class I areas in Tennessee and IMPROVE monitors that represent 

conditions at each of them. 
106

In addition to the IMPROVE measurements, some ongoing long-term limited monitoring 

supported by Federal Land Managers provides additional insight into progress toward 

regional haze goals. Tennessee benefits from the data from these measurements, but is not 

responsible for the funding decisions to maintain these measurements into the future. Such 

measurements include: 

• Web cameras operated by the National Park Service at Look Rock, TN at the Great 

Smoky Mountains National Park 

• An integrating nephelometer for continuously measuring light scattering, operated by 

the National Park Service at Look Rock, TN. 

• A Tapered Element Oscillating Microbalance (TEOM) for continuously measuring 

PM2.5 mass concentration, operated by the National Park Service at Look Rock, TN. 

In addition, TDEC-APC and the local air agencies in the State operate a fairly 

comprehensive PM2.5 network of the filter based Federal reference method monitors, 

continuous mass monitors (TEOMs) and filter based speciated monitors. A map of the 

various locations around the State is included in Figure 9.0.1. These PM2.5 measurements 

help TDEC-APC characterize air pollution levels in areas across the state, and therefore aid 

in the analysis of visibility improvement in and near the Class I areas. 

Figure 9.0.1 PM2.5 Monitoring Network in Tennessee 
107

The IMPROVE measurements are central to Tennessee’s regional haze monitoring strategy, 

and it is difficult to visualize how the objectives listed above could be met without the 

monitoring provided by IMPROVE. Any reduction in the scope of the IMPROVE network in 

Tennessee would jeopardize the State’s ability to demonstrate reasonable progress toward 

visibility improvement in its Class I areas. 

Data produced by the IMPROVE monitoring network will be used nearly continuously 

for preparing the 5-year progress reports and the 10-year SIP revisions, each of which 

relies on analysis of the preceding five years of data. Consequently, the monitoring data 

from the IMPROVE sites needs to be readily accessible and to be kept up-to-date. 

Presumably, IMPROVE will continue to process information from its own measurements 

at about the same pace and with the same attention to quality as it has shown in the 

recent past. The VIEWS web site has been maintained by VISTAS and the other Regional 

Planning Organizations to provide ready access to the IMPROVE data and data analysis 

tools. TN is encouraging VISTAS and the other RPOs to maintain VIEWS or a similar 

data management system to facilitate analysis of the IMPROVE data. 

EPA Findings: Tennessee has appropriately addressed this provision. 
108

III. Evaluation of State Regional Haze Submittal 

G. Emission Inventory (40 CFR 51.308(d)(4)(v) (See also EPA TSD Section 

III.C.) 

The plan must include a statewide inventory of emissions of pollutants that are 

reasonably anticipated to cause or contribute to visibility impairment in any mandatory 

Class I Federal area within the state. The inventory must include emissions for a baseline 

year, emissions for the most recent year for which data are available, and estimates of 

future projected emissions, and a commitment to update the inventory periodically. 

State Regional Haze Submittal 

Pages 19, 23, 49, 93 

The Regional Haze Rule at 51.308(d) (4) (v) requires a statewide emissions inventory of 

pollutants that are reasonably anticipated to cause or contribute to visibility impairment 

in any mandatory Class I area. An inventory was developed for the baseline year 2002 

and projected to 2009 and 2018. The pollutants inventoried include volatile organic 

compounds, nitrogen oxides, fine particulate (PM2.5), coarse particulate (PM10), 

ammonia and sulfur dioxide. The baseline emissions inventory for 2002 was developed 

for Tennessee following the methods described in Appendix D. 

There are five different emission inventory source classifications: stationary point and 

area sources, off-road and on-road mobile sources, and biogenic sources. Stationary 

point sources are those sources that emit greater than a specified tonnage per year, with 

data provided at the facility level. Electric generating utilities and industrial sources are 

the major categories for stationary point sources. Stationary area sources are those 

sources whose individual emissions are relatively small, but due to the large number of 

these sources, the collective emissions from the source category could be significant (i.e., 

dry cleaners, service stations, agricultural sources, fire emissions, etc.). These types of 

emissions are estimated on a countywide level. Non-road (or off-road) mobile sources 

are equipment that can move but do not use the roadways, i.e., lawn mowers, 

construction equipment, railroad locomotives, aircraft, etc. The emissions from these 

sources, like stationary area sources, are estimated on a countywide level. On-road 

mobile sources are automobiles, trucks, and motorcycles that use the roadway system. 

The emissions from these sources are estimated by vehicle type and road type and are 

summed to the countywide level. Biogenic sources are the natural sources like trees, 

crops, grasses and natural decay of plants. The emissions from these sources are 

estimated on a countywide level. 

In addition to the various source classifications, there are also various types of emission 

inventories. The first is the actual base year inventory. This inventory is the base year 

emissions that correspond to the meteorological data used, which for this modeling effort 

is data from 2002. These emissions are used for evaluating the air quality model 

performance. 

The second type of inventory is the typical base year inventory. This inventory is similar 

to the actual base year inventory, except that for sources whose emissions change 
109

significantly from year to year, a more typical emission value is used. In this modeling 

effort, typical emissions were developed for the electric generating units (EGUs) and the 

wildland fire emissions. The air quality modeling is run using the typical base year 

inventory and the future year inventory. The results from these two runs are then used to 

calculate relative reduction factors. These relative reduction factors for future years are 

then used to demonstrate reasonable progress toward visibility goals. 

Table 4.1.6-1 is a summary of the 2002 baseline actual Base G4 (Best and Final) 

emission inventory for Tennessee. Table 4.1.6-2 is a summary of the 2002 baseline 

typical emission inventory. The complete inventory and discussion of the methodology is 

contained in Appendix D. The emissions summaries for other VISTAS states can also be 

found in Appendix D. 

Table 4.1.6-1 2002 Actual Base G4 (B&F) Emissions Inventory Summary for TN in 

tons per year. 

Source Category VOC NOx PM2.5 PM10 NH3 SO2 

Point 85,254 221,651 39,973 49,814 1,817 413,755 

Area 153,509 17,936 42,925 212,972 34,412 29,942 

On-Road Mobile 179,807 238,577 3,949 5,371 6,625 9,226 

Non-Road Mobile 66,450 96,827 6,458 6,819 43 10,441 

Biogenics 894,214 18,081 0 0 0 0 

TOTAL 1,379,234 593,072 93,305 274,976 42,897 463,364 

Table 4.1.6-2 2002 Typical Base G4 (B&F) Emissions Inventory Summary for TN in 

tons per year. 

Source Category VOC NOx PM2.5 PM10 NH3 SO2 

Point 85,218 216,481 39,298 49,040 1,810 399,750 

Area 153,783 18,061 43,410 213,538 34,439 29,977 

On-Road Mobile 179,807 238,577 3,949 5,371 6,625 9,226 

Non-Road Mobile 66,450 96,827 6,458 6,819 43 10,441 

Biogenics 894,214 18,081 0 0 0 0 

TOTAL 1,379,472 588,027 93,115 274,768 42,917 449,394 

Summary of Emissions Inventories for 2009 and 2018 

Tables 7.2.3-1 and 7.2.3-2 are summaries of the 2009 and 2018 Base G4 (Best and Final) 

emission inventory, respectively. The complete inventory and discussion of the 

methodology is contained in Appendix D. 

Table 7.2.3-1. 2009 Base G4 (B&F) Emissions Inventory Summary for TN. 

Source Category VOC NOx PM2.5 PM10 NH3 SO2 

Point 74,430 123,919 40,459 50,189 2,067 320,374 

Area 155,194 18,872 45,573 227,787 35,331 30,679 

On-Road Mobile 115,181 151,912 2,751 4,206 7,782 1,076 

Non-Road Mobile 55,358 86,641 5,557 5,877 48 5,651 

Biogenics 894,214 18,081 0 0 0 0 
110

TOTAL 1,294,377 399,425 94,340 288,059 45,228 357,780 

Table 7.2.3-2. 2018 Base G4 (B&F) Emissions Inventory Summary for TN. 

Source Category VOC NOx PM2.5 PM10 NH3 SO2 

Point 93,432 94,234 46,680 57,940 2,454 169,354 

Area 183,110 20,002 48,265 248,086 36,376 32,073 

On-Road Mobile 67,324 69,385 1,544 3,092 9,021 948 

Non-Road Mobile 45,084 70,226 4,403 4,672 55 5,207 

Biogenics 894,214 18,081 0 0 0 0 

TOTAL 1,283,164 271,928 100,892 313,790 47,906 207,582 

The requirements listed in 51.308(g) include the following: 

.... 

Summary of emission reductions achieved thus far, including especially the status of 

implementation of the CAIR compliance plans for EGUs compared to the control 

assumed in the modeling. 

... 

Analysis of emission changes over the 5-year period, identified by source or activity; 

... 

All requirements listed in 51.308(g) shall be addressed in the SIP revision for reasonable 

progress. 

There are several technical improvements that are recommended in the emissions 

inventory and air quality models that are used to support regulatory decisions for 

regional haze. These improvements will be considered as recommended, and as funding 

is available, to support the next long term strategy. 

EPA Findings: Tennessee has appropriately addressed this provision. 
111

IV. Conclusion 

Except for those aspects of the Regional Haze submittal that rely on EPA’s CAIR Rule, 

Tennessee’s Regional Haze SIP, submitted on April 4, 2008, meets all of the 

requirements of section 110 of the CAA and meets the Regional Haze requirements, as 

set forth in sections 169A and 169B of the Act and in 40 CFR 51.300-308, including by 

requiring the establishment of reasonable progress goals for each of its Class I areas, 

determining Best Available Retrofit Technology (BART), and submitting a long-term 

strategy that addresses regional haze visibility impairment for its Class I areas and for 

those Class I areas in other States that may be impacted by emissions from within 

Tennessee. 

 
112