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, GA2 

### 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 Goal s (RPGs) Development

1. Calculations of Baselin e Visibility Conditions

2. Calculations of Natural Visibility Conditions

3. Uniform Rate of Progre ss (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 Categor y Specific Analyses for Reasonable Progress

4. Enforceability of Reasonable Progress Measures

D. Best Available Retrofit Techno logy (BART) Requirements

1. Identification of all BART-Eligible Sources

2. Modeling or other Demo nstrations 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 Impa irment (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 submitta l. 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 ex isting, impairment of visibility in mandatory Federal Class I areas which impair ment results from ma nmade air pollution.” Congress adopted the visibility provisions to protect visibility in 156 Federal Class I areas, which include certain national parks, me morial 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 visibil ity impairment that is “reasonably attributable” to a single source or small group of sources . (45 FR 80084) These regula tions 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 pollutant s 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 exis ting visibility regula tions to integrate provisions addressing regional ha ze visibility impairment and establish a comprehensive visibility protection program fo r 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 wi th other states and with Federal Land Managers (FLMs). States must submit a re gional 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 (PM 2.5 ). EPA promulgated PM 2.5 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 po llution sources over a wide geographic region. Consequently, all 50 states, including those without Class I areas, Washington, D.C., and the Virgin Is lands, are required to submit Regional Haze SIPs. (40 CFR 51.300(b)(3)). The US EP A designated five Regional Planning Organizations (RPOs) to assi st 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 (Visib ility Improvement – State and Tribal Association of the Southeast). VISTAS me mbers 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, Te nnessee, Virginia, and West Virginia. The State of Tennessee Department of Environm ent and Conservation th rough the Tennessee Division of Air Pollution Control (TDEC-AP C) chose to participate in VISTAS to develop the technical analyses needed to fulfill the requirements of the RHR.4 Figure 1. Geographical Areas of Regi onal Planning Organizations

Figure 2. Class I Areas in the VISTAS Region5 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 an thropogenic impairment of visibility in mandatory Class I areas caused by emissions of air pollutants from numerous sources located over a wide geographic area (also refe rred to as the “regional haze program”). States are required to assure reasonable pr ogress toward the nati onal 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 Te nnessee SIP. Also in this action, EPA is proposing a limited disapproval of this same SI P 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 Distri ct of Columbia (D.C. Circui t) to EPA of the Clean Air Interstate Rule (CAIR).6 III. Evaluation of Region al 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 Tenne ssee 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 K ilmer – 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, No rth 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 Kilmer
Slickrock7 III. Evaluation of Region al Haze Submittal B. Reasonable Progress G oals (RPGs) Development
B.1.Calculations of Baselin e Visibility Conditions: ((40 CFR 51.308(d)(2)(i)) The period for establishing baseline visibi lity 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 (expre ssed in deciviews) for the most impaired and least impaired days (i.e. the 20 percen t 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 Fede ral area located within the state, the plan

needs to calculate the number of deciview s by which baseline conditions exceed natural visibility conditions for th e most impaired and least impaired days. Where onsite monitoring is not available the baseline visibil ity 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 monito ring 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 conside rs the IMPROVE monitor at Grea t Smoky Mountains to be representative of visibility in the Joyce Kilmer area. Th e 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 in cluded 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 addresse d this provision. In cases where onsite monitoring is not available, 40 CFR 51.30 8(d)(2)(i) requires stat es to use the most representative monitoring available for the 2000-2004 period to establish baseline visibility conditions, in consultation with US EPA. EPA concurs w ith the use of data8 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 ar e contiguous to one another, and the areas possess similar characteristics, such as meteorology and topography.9 III. Evaluation of State Re gional Haze Submittal B. Reasonable Progress G oals (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 visi bility impairment existing under natural conditions for the most impa ired and least impaired days, based on available monitoring information and appropriate data analysis techniqu es 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 fi ne particle components. The same annual average natural background visibility is assu med for all Class I areas in the eastern United States (separate values are estimate d for the western United States). Natural background visibility for the 20 percent worst days is estimated by assuming that fine particle concentrations for natural backg round are normally distributed and the 90 th
percentile of the annual distri bution represents natural bac kground visibility on the 20 percent worst days (i.e, Method 1 predic tion 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 in clude the concentrati on values, factors to calculate extinction from a measured particul ar species and particle size, the extinction coefficients for certain compounds, geographical variation (by altitude) of a fixed value, and the addition of visibilit y pollutants.

In 2005 the IMPROVE Steering Committee m ade recommendations for a refined equation that modifies the terms of the orig inal 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 th e state in which the Class I area is located.

The VISTAS states chose to use the ne w 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 KilmerSlickrock 11.1 4.5 30.8 15.8

EPA Findings : EPA required the State of Tenness ee 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 a pproval 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 addre ssed this provision.11 III. Evaluation of State Re gional Haze Submittal B. Reasonable Progress G oals (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. Fo r 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 maintain ed 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 le ast 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 determ ine RPGs and does not determine whether reasonable progress ha s 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 toward s reaching natura l background.

State Regional Haze Submittal Pages 86-88

The Regional Haze Rule at 40 CFR section 51.308(d)(1) requires St ates to establish reasonable progress goals for each Cl ass I area within the state ( expressed in deciviews) that provide for reasonable progress towards achiev ing natural visibility. In addition, USEPA released guidance on June 7, 2007 to use in setting reasonable progr ess 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 SI P 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 Cla ss I area in Tennessee. To calculate the rate of progress represented by each re asonable progress goal, TDEC-APC compared baseline visibility conditions to natural visibility conditi ons in each Class I area and determined the uniform rate of visibility improvement (in decivi ews) 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 Reasonabl e 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 pe rcent most impaired days for Great Smoky Mountains National Park and Joyce Kilm er-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 nat ural conditions estim ates (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



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64

YearHaziness Index (Deciviews)

Glide Path Natural Condition (Worst Days) Observation Method 1 Prediction13 (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



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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

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YearHaziness Index (Deciviews)

Glide Path Natural Condition (Worst Days) Observation Method 1 Prediction14 Appendix G, Pages G-5 – G-10

2 Reasonable Progress Goals

For each Class I area, there are three metr ics 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 con centration data of the visibility impairing pollutants as different terms in the light ext inction algorithm, with respective extinction coefficients and relative humidity factors. To tal 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 dete rmine 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 c ontrols. After the potential control analysis, reasonable progress goals for the Class I area s are determined after consultation with surrounding states. The entire RPG determ ination 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 par ticulate matter are used to es timate visibility impairment at some future date. The modeling is applie d in a relative sense, similar to the fine particulate matter (PM25) attainment test. Th e 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, PM 2.5 , 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 PM 2.5 data for each of the 5 years comprising the base period (2000-2004) for each Class I area. Da y-specific observations for mass associated with sulfate (SO 4 ), nitrates (NO 3 ), organic carbon (OC), elemental carbon (EC), soil, and coarse matter (CM), should be used to calculate b ext for each day using climatological relative humidity adjustment factor(s) (f(rh)). Total light extinction (b ext ) for all components should be converted to deciviews for each day to ge t a daily deciview value.15 3.2 Determine Baseline Conditions

The ranked visibility days from the first st ep 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 (dv current ). The 5 year mean deciview values reflecting mean visibility on the days with best visibility and then averaged to determine the baselin e values for the best days, or the dv baseline values. Then the 5 year mean deciview valu es reflecting worst visibility are averaged together. This represents the value subjec t 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 Inter agency Monitoring of Protected Visual Environments (IMPROVE) monitoring sites at on e of the two Class I areas in Tennessee. A five year average (2000 to 2004) was calculat ed for each of the 20 percent worst and 20 percent best visibility days in accor dance with 40 CFR 51.308(d)(2) and the USEPA’s Guidance for Tracking Progress Under the Re gional Haze Rule. IMPROVE data records for Great Smoky Mountains for the peri od 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 Joyc e 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 extin ction 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 bas eline 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.

dv baseline Natural Condtions dv baseline 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 PM 2.5 on the 20% best and worst monitoring days. Simply put, the RRF is the average future year c oncentration near the monitor divided by the average base year concentration or:

ion Concentrat Year Base Modeled Average ion Concentrat Year Future Modeled Average

= RRF16 To accomplish this step, concen tration for each component of PM 2.5 and coarse matter (the difference between particles less than 10 micrometers in diameter (PM 10

) and PM 2.5

) are extracted from the base year and fu ture year modeling output near IMPROVE monitoring sites for th e 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 concentra tions are then divided by their respective base year component concentrations to develop RRFs for each component of PM 2.5 and

coarse matter.

For a numerical example, consider Table 3.3- 1, which has all the pe rtinent data for the GSMNP1 IMPROVE monitor. Looking at the t op table, the first column identifies the 20% best days identified in step 1 (Secti on 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 yea r concentration. The bo ttom 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 RRFs18 3.4. Future Year Daily Concentration Calculation

The fourth step in using mode l output to estimate the future visibility impairment is to multiply the relative response factors (determine d in the previous step, Section 3.3) by the measured species concentrati on 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. D VF = 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 produ ces future concentration estimates for SO 4 , NO 3 , OC, EC, Soil and CM, for each of the “w orst” and “best” visibility days.

3.5. Future Year Daily bext Calculation

Once future year concentrations are calculat ed (Section 3.4) the fu ture 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 * f
s (RH) * [Small Sulfate] + 4.8 * f L (RH) * [Large Sulfate] + 2.4 * f
s (RH) * [Small Nitrate] + 5.1 * f L (RH) * [Large Nitrate] + 2.8 * {Small Organic Mass] + 6.1 * [Large Organic Mass] + 10 * [Elemental Carbon] + 1 * [Fine Soil] + 1.7 * f
ss (RH) * [Sea Salt] + 0.6 * [Coarse Mass] + Rayleigh Scattering (site specific) + 0.33 * [NO 2 (ppb)]

Model estimated daily concentrations are used with the corres ponding base line daily relative humidity adjustment factor(s) (f(r h)) identified in st ep 1 (Section 3.1).

3.6. Future Mean Deciview Values Calculation

The final step is to calculate daily decivi ew values from the total daily extinction calculated in the previous step, and then co mpute the future aver age 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 valu e for the worst and best days.

The first step in this process is to convert the total daily b ext 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 determin e the future deciview value19 for the “worst” and “best” visibi lity days for each year. This leads to 5 future estimated mean deciview values for the “worst” and 5 fu ture 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 futu re mean deciview value, or dv future . 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% be st days (right column ). The last row in the table displays the final future mean deciview value, or dv future

.

Table 3.6-1: Final future mean deciview values (dv future ) and Natural Conditions for the Tennessee Class I areas, bas ed on 12km modeling results.

dv

future Natural Condtions dv future 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 dv future values for the “worst” and “best” visibility days can be compared

to the dv baseline values calculated in step 2 (Sec tion 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 thes e calculation for the IMPROVE monitors

associated with Tennessee Class I areas. Fr om the table, it is apparent that the two Tennessee Class I areas are showing visibil ity improvement on both the 20% best and 20% worst days.

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

baseline deciview estimates.

Site DV base DV future DV diff DV base DV future DV diff 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 a ddressed this provision.20 III. Evaluation of State Re gional 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 ba sis, including modeling, monitoring and emissions information, on which the State is rely ing to analyze regional haze. The State may meet this requirement by relying on tec hnical analyses developed by the regional planning organization and appr oved 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 approx imately 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 re ferred to as “on th e books” or “on the way” (OTB/OTW).

II. Modeled expected visibility improvemen t 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 sens itivity model runs to help determine which pollutants and source categories are contributing the mo st 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’ Cl ass I areas whose AoI includes any Tennessee sources, to determine which spec ific sources are most likely to be impairing visibility.

V. Application of the four “s tatutory 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 im provement after inclusion of BART and reasonable progress control determinations.21 XI. Determination of RPGs based on the visi bility 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 ou tline the methods and inputs used by VISTAS for the regional modeling. Add itional details are provided in Appendices C, D and M. The modeling analysis is a comp lex 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) Meso scale Meteorological Model (MM5) is a nonhydrostatic, prognostic meteorological model rout inely 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 genera tes 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 Multis cale Air Quality (CMAQ) modeling system is an ‘One-A tmosphere’ 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 dom ain. 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 th e 12-km grid over the VISTAS region.

Care was taken in the selection of the m odeling 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 suffici ent detail, using peer-reviewe d methods. Freely accessible means that model formulations and coding are freely availa ble 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) Meteorologi cal inputs were developed for 2002 using the MM5 meteorological model. Confi gurations for the modeling MM5 and CMAQ modeling domains are summarized and discu ssed on pages 32-31, additional details are provided in the appendices) Emission in ventories were also developed for 2002 and processed through the emissions model. Thes e 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 qualit y data to evaluate model performance. Several configurations of the meteorologica l and air quality model were evaluated to select a configuration that gave the best overall perform ance for the VISTAS region.

Emissions Controls Modeled (pages 43-47 SIP Narrative)

There are significant control programs bei ng 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 implemen ted, CAIR will reduce SO2 emissions from EGUs in these states by more than 70 pe rcent, and NOx emissions by more than 60 percent, from 2003 levels. For TVA, the electri c utility that operates coal-fired EGUs in Tennessee, the following tables reflect the reductions expected:

Emissions are aggregated at the facility level, rath er 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 PM 10 Emissions (tons) SO 2 Emissions (tons) NO X

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 11,45624 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 SO 2 Controls (2006) Projected SO 2 Controls**

Allen None. Plant burns low-sulfur fuel. 2006 emission rate was

0.62 lb/mmBtu SO 2

. 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 SO 2. None planned prior to 2015.

John Sevier None Scrubber. Completion projected

in 2012.

Johnsonville None Testing is underway to determine the viability of reducing SO 2 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 SO 2 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 appl ies to certain EGUs and large nonEGUs, including large industria l boilers and turbines, and cement kilns. Those states affected by the NOx SIP call in the VISTAS re gion 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 legisl ation 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 mu st 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 estim ated 75-85% by 2015. Reductions will affect 21 units at seven facilities. The rule requires specific cont rols on specific units according to a specific schedule. This is not a cap and trade ru le, 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 m eet stringent pollution limits; implement a series of interim pollution-r eduction measures to reduce em issions while the permanent controls are designed and installed; and retir e 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 Sou thern District of Ohio, East ern Division]: In October 2007 American Electric Power agreed to spe nd $4.6 billion dollars to eliminate 72,000 tons of NOx emissions each year by 2 016 and 174,000 tons of SO2 emissions each year by 2018 from sixteen coal-fired power pl ants located in Indi ana, Kentucky, Ohio, Virginia and West Virginia.

A 2002 agreement calls for Gulf Power to upgrad e its operation to cut NOx emission rates by 61 percent at its Crist genera ting plant by 2007, with major reductions beginning in early 2005. The Crist plant is a si gnificant 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 atta inment of the one-hour ozone National Ambient Air Quality Standard (NAAQS). Th ese 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 ar ea includes Reasonable Achievable Control Technology (RACT) for NOx for two facilities locate d 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 we re 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 NO x 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 must26 be lowered to enable modern pollution-control technology to be eff ective on these trucks and buses. USEPA will require a 97 percent redu ction 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 Californ ia LEV II standards. Manufacturers can produce vehicles with emissions ranging from relatively dirty to zero, but the mix of vehicles a manufacturer sells ea ch year must have average NO

x emissions below a specified value. Tier 2 standards became effective in the 200 5 model year.

Large Spark Ignition and R ecreational Vehicle Rule . USEPA has adopted new standards for emissions of ox ides of nitrogen (NOx), hydrocarbons (HC), and carbon monoxide (CO) from several groups of pr eviously unregulated nonroad engines. Included in these are large industrial spark-ig nition engines and recreational vehicles. Nonroad spark-ignition engines are those pow ered by gasoline, liquid propane gas, or compressed natural gas rated over 19 kilo watts (kW) (25 horsepower). These engines are used in commercial and industrial applic ations, including forklifts, electric generators, airport baggage tr ansport vehicles, and a variet y of farm and construction applications. Nonroad recrea tional vehicles include s nowmobiles, 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 re duce sulfur levels by 99 percent from current levels in nonroad diesel fuel star ting 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 ai r pollutants from industrial, commercial and institutional boilers, process heaters and from stationary reci procating internal combustion engines (RICE). These rules re duce 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 pe rcent for SO2 and 40 percent for PM 10 and PM 2.5 . The USEPA’s industrial boiler MACT rules were vacated on June 8, 2007. The VISTAS

states decided to leave these controls in th e 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 Reciprocating27 Internal Combustion Engines, which USEPA es timates 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 impl emented. Reductions o ccurring 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 furthe r reasonable progress measur es is to identify the key pollutants contributing to visibility impairment at each Class I area. To understand the relative benefit of further reduc ing emissions from d ifferent pollutants, source sectors, and geographic areas, VI STAS engaged the Georgia Institute of Technology to perform emission sensitivity model runs using CMAQ. Emissions in 2009 were reduced by 30 percent for each pollu tant sensitivity run. The pollutant

contributions that we re 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 ea ch 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 st ates, these reductions were only applied to specific counties that were of c oncern 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 anthr opogenic and biogenic sources in the 12 km modeling domain

• Primary Carbon from all ground level sour ces in each VISTAS state and other RPOs. In the VISTAS states, these re ductions were only applied to specific counties that were of concern for PM 2.5 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 percen t worst days that were modeled in the two episodes. These results were used to unde rstand the relative impor tance of pollutant

contributions at this site.28 Figure 7.4-1. CMAQ projections of visibili ty 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 visibi lity 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 reducti ons from non-utility, industrial point sources. The pattern of relative SO2 cont ributions 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 gr eatest visibility bene fits for the Tennessee Class I areas. Contributions from the Midwest RPO and MANE-VU are greater at the Class I areas bordering these RPOs. Contri butions from outside the VISTAS 12-km modeling domain are more important for the coastal Class I areas.

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

The initial modeling effort focused on eval uating previous regional air quality modeling applications and testing candidate model conf igurations 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)

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0.00

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O2_E GU

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P

C

_Fires∆Bext(Mm-1) Bio VOC.

Anthro VOC

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MRPO

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WV

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SC

NC

MS

KY

GA

FL

AL 

### Great Smoky Mtns, TN (20% Worst Days)

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_Fires∆Bext(Mm-1) Bio VOC.

Anthro VOC

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VISTAS

WV

VA

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SC

NC

MS

KY

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FL

AL29 in a report recommending the model confi guration for the annual emissions and air quality modeling, which is included as part of the VISTAS Emissi ons 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 mode ling year was initially tested in 2004 using an early version of the VISTAS emissi ons inventory. In keeping with the oneatmosphere objective of the CMAQ mode ling platform, model performance was evaluated based on measured ozone, fine particle s, 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 Netw ork (CASTNet) monitoring networks

The air quality model’s performance was evaluated with respect to individual components of fine particulate matter (PM 2.5

), as good model performance of the component species will dictate good model perf ormance of total or reconstituted fine particulate matter. Model performance of the total fine particulate matter and the resulting total light extinction was also provid ed 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 crit eria levels used fo r regional haze model performance were 30% and 60%, respectivel y, for mean fractional bias and 50% and 75%, respectively, for mean fractional error. Plots were presented for the average monthly concentrations and the pe rformance statistics for all of the most significant light scattering component species (Sulfate, Nitr ate, and Organic Carbon) for the 20% best days and 20% worst days. Plots for indi vidual 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 outsi de of criteria performance thresholds (red box). Sulfates and organic carbon generally fall within goal th resholds (green box), with a couple of months falling just outside the goal thresholds but well within the criteria thresholds. In these figures, each point repres ents a month. Figure 6.2-3 cont ains separate soccer plots for each season. The seasonal plots emphas ize poorer nitrate performance in the summer (does not even appear on the plots pr ovided because performance is off scale with other constituents), when observed nitrat e is quite low and predic ted nitrate is even lower. When concentration is factored in to performance criteria, nitrate performance improves with respect to mean fractional bi as 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 f ound the Base G2 modeling results to be30 representative and acceptable for use in modeling projec tion 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 BiasMean 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 BiasMean Fractional Error Sulfate

Nitrate

Organics

Criteria

Goal

Figure 6.2-2: A zoomed view of the soccer pl ot depicting both the mean fractional error and fractional bias for component concentration for all VISTAS sites.

V ISTAS 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 BiasFractional Error Sulfate

Nitrate
Ammon. Organics
EC

Soils
PM25

PM10
CM
Criteria

Goal V ISTAS 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 BiasFractional Error Sulfate

Nitrate
Ammon. Organics
EC

Soils
PM25

PM10
CM
Criteria

Goal31 Figure 6.2-3: Seasonal soccer plot s 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 ( μ g/m 3 )Mean Fractional Error Sulfate

Nitrate

Organics

Criteria

Goal

Figure 6.2-4: Bugle plot of the mean fracti on bias for particulate matter and its component
concentrations for all VISTAS sites. V ISTAS 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 BiasFractional Error Sulfate

Nitrate
Ammon. Organics
EC

Soils
PM25

PM10
CM
Criteria

Goal V ISTAS 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 BiasFractional Error Sulfate

Nitrate
Ammon. Organics
EC

Soils
PM25

PM10
CM
Criteria

Goal32 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 ( μ g/m 3 )Mean Fractional Bias Sulfate

Nitrate

Organics

(+) Criteria

(+) Goal

(-) Goal

(-) Criteria

Figure 6.2-5: Bugle plot of mean fraction e rror 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 modele d fine particulate matter co mposition. 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 th e Great Smoky Mountains Nati onal Park (GSMNP1). (See Figure 1.4-1). The Great Smoky Mountains Na tional 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 th e 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 me asured values. For 20% worst days total33 differences between modeled and measured extinction varies fr om 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 s uggest 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 pred iction, 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% be st 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 im portant 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 performanc e over the 20% best day series, though some days are still under predicted. Over all, TDEC-APC found model performance to fall within acceptable limits for model perfor mance. TDEC-APC further asserts the one atmosphere modeling performed by the VI STAS 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 Datebext (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 Datebext (1/Mm) bextCM

bextSOIL

bextEC

bextOC

bextNO3

bextSO4

Figure 6.3-1: Stacked bar char t 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 modelin g 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 mode ling to assess uniform rate of progress and to support the LTS were successfully de veloped 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 SO 2 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 v acate 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 fo r 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 valu es 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 acti on. 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 pr ogress provisions affecting its EGUs was adequate. The regional haze provisions speci fy that a state may not adopt a RPG that represents less visibility improvement than is expected to re sult from other CAA requirements during the pla nning period (40 CFR 51.308(d)(1)(v i)). As such, Tennessee took into account emission reductions anticipa ted 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 H aze SIP revisions that rely on CAIR.36 Also, on July 30, 2007, the U.S. District Court of Appeals ma ndated the vacatur

and remand of the Industrial Bo iler MACT Rule. Notwithstandi ng the vacatur of the this rule, the VISTAS states, incl uding Tennessee, decided to le ave 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 ac ceptable for the following reasons. EPA proposed a

new Industrial Boiler MACT rule to addr ess 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 pr ior to the end of the first implementation period in 2018. In the absence of an esta blished MACT rule for boilers and process heaters, the statutory language in section 112(j) of the C AA 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 implem ent section 112(j) of the CAA for industrial boilers, EPA would expe ct, in this case, that compliance with case-by-case MACT limits for i ndustrial 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 SO 2 , PM 2.5 , and coarse particulate matter (PM 10 ) emissions in 2018 (i.e., 0.5 to 1.5 percent, depending on the pollutant, of the projected 2018 SO 2 , PM 2.5 , and PM 10 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 re ductions achieved by the replacement MACT, EPA would not expect that th is 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, PM 2.5 , 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 Attainme nt of Air Quality

Goals for PM 2.5 and Regional Haze”, http://www.e pa.gov/ttn/scram/guidance_sip.htm

3. 2002 Base Year Emission Invento ry SIP Planning: 8-hr Ozpne

, PM 2.5 and Regional

Haze US EPA memorandum from Lydia Wegm an 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 notifica tion to the Administrator and affected

States.38 III. Evaluation of State Re gional 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 sour ces of visibility impa irment considered by the State in developing its l ong-term strategy. The State should consider major and minor stationary sources, mobile sources, and ar ea sources. The State must consider, at a minimum, the following factors in devel oping its long-term st rategy: (A) emission reductions due to ongoing air pollution contro l programs, including measures to address reasonably attributable visibility impairmen t; (B) Measures to mitigate the impacts of construction activities; (C) Emissions limitatio ns and schedules for compliance to achieve the reasonable progress goal; (D) source re tirement and replacement schedules; (E) smoke management techniques for agricultu ral and forestry management purposes including plans as currently exist within the State for these purposes; measures to mitigate the impacts of construction activitie s; (F) enforceability of emission limitations and control measures; and the (G) anticipated net effect on visibili ty 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 de termining 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 emissi ons in 2018 are projected to re present 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 Ru le (CAIR) is suffi cient for reasonable progress for subject EGUs.

TDEC-APC evaluated the am ount of SO2 reduction from the EGU sector based upon
consultations with TVA. The EGUs in Tenne ssee are expected to redu ce their SO2 emissions39 by approximately 75% between 2002 and 2018. T VA reduced significant (~58% from the 1994 to 2002 time period) SO2 emission tonnage pr ior to that under Ph ase I acid rain reductions as a part of the Titl e IV Program for an overall 20 18 reduction of >85%. TDECAPC believes it has an accurate understanding of where emission reductions will occur in the Tennessee EGU sector based upon fixed insta llations 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 th e visibility analysis requirements as required in the federal NSR/PS D 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 ar e periodically updated,

TDEC-APC declares that this statement is simply a recitation of the rules and not an inclusion of the current ve rsion of the rule into the Tennessee Regional Haze SIP.

Step 4: Determine which emission un its would be evaluated based on impact.

TDEC-APC calculated the frac tional contribution from all em ission 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 discussi on. Some sources had greater than one percent impacts, but TDEC-APC did not request a f our-factor analysis from the source due to information already in the possess ion of the agency. A brief de scription of these sources is as follows:

• Intertrade Holdings in Polk County – The majority of the source is being dismantled and being shipped out of th e country. The remaining operations have very little sulfur dioxide emissions.

• TVA’s Bull Run Fossil Plant in Anderson Count y 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 re duction was not recognized in the inventories used to perform the VISTAS modeling. The com pany 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 t ons) 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 re quired at this facility for this review period. As predicted visibility levels are replac ed with future measured visibility levels, a reassessment of the facility’s SO 2 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 Sulliv an 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 conc rete plant with a 2018 future projected source emission strength of 200 tons per year of SO 2 . At this level, there was a resulting 3.9 percent impac t at the Great Smoky Moun tains National Park. In actuality, the facility is an asphalt drum mix plant with a current SO 2 allowable of 20.3 TPY. For illustration purposes only, if this value were doubled to a 2018 emission rate of 40 TPY, the predic ted impact would be 0.0077 percent, well below the impact evaluation l evel of one percent. Fo r these reasons, no further attempts were made to evaluate the facility under the four-factor analysis.

• United States Department of Energy Y-12 Pl ant 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 repowe ring 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 fu rther 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 Areas41 Joyce Kilmer-Slickrock - Point Source SO 2 Contribution to TN Class I Areas

Step 5: Evaluate the four factors.

Each emission unit identified in Step 4 above is being eval uated using the statutory and regulatory factors of 1) cost of compliance, 2) time necessary for compliance, 3) the energy and non-air quality environmental im pacts 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 lis ts several factors that must be addressed in each SIP. These factors in clude the role of fire at Cl ass I areas and status of state planning for smoke management, the role of dus t and fine soil at Class I areas and status of state plans to mitigate emissions from c onstruction activities, and the role of NH3 and potential benefits if emissions from agricultural sources were mitigated.

As discussed in Section 2.4 and demonstr ated in Figures 2.4-1 and 2.4-2, elemental carbon (sources include agriculture, prescrib ed wildland fires, and wildfires) is a relatively minor contributor to visibility im pairment 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 flexi bility reasons. It would simply be too42 cumbersome to formally revise the SI P for minor changes to a smoke management program or plan. Any resulting plan would si mply 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 demons trated in Figures 2.4-1 and 2.4-2, fine soils are a relatively minor contribut or to visibility impairmen t at the Class I areas in

Tennessee. TDEC-APC has an effective relationship with the Tennessee Department of Transportation (TDOT) in working on air qual ity action days, diesel retrofits of construction equipment, distri bution of alternative fuels and the innovative use of the Congestion Mitigation and Air Quality Im provement Program (CMAQ) money to improve air quality in nonattainment ar eas. 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-descri bed 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 a ssurance that the proven plan has more than adequate measures with these incidental me asures present as an unrelied upon backup.

In addition, TDEC-APC’s Rule 1200-3-8-.03 re quires additional control measures on source operating permits to control dust emis sions. That rule and the entire Chapter 1200-3-8 for controlling fugi tive dust may be seen at: http://tennessee.gov/sos/r ules/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 Sectio n 7.2.1, any controls resulting from BART

determinations within the VIST AS states and any controls resu lting 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 incorporat e these findings in the final SIP, including revising reasonable progress goal s if needed. If th e modeling runs and analyses are not completed in time, TDEC-APC will review the info rmation 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 progre ss 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 establishing43 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 c ontrol 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 SO 2 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 fr om William L. Wehrum , Acting Assistant Administrator for Air and Radiation, to EPA Regional Administrators, EPA Regions 1- 10, Guidance for Setting Reasonable Progress G oals under the Regional Haze Program,44 III. Evaluation of State Re gional 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 categor ies located within the State and determined to be significantly impacting a mandatory Cl ass 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 environmenta l impacts of compliance, th e remaining useful life of any potentially affected sources, and how thes e factors were taken in to consideration in establishing the reasonable progress goal.

State Regional Haze Submittal Pages 84-85 Each emission ... is being evaluated using the st atutory and regulatory factors of 1) cost of compliance, 2) time necessary for comp liance, 3) the energy and non-air quality environmental impacts of compliance, and 4) the re maining 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 sh ould 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 pow er boilers that constitute the bulk of its facility SO2 emissions. Bowater presented info rmation and data in its four-factor analysis

that lead TDEC-APC to conclude that it shou ld not have to install SO2 post combustion

controls nor switch to lower su lfur 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 overstat ed and that the growth proj ections 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 determina tion 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-A PC agreed, that with fuel-switching becoming a favored option among a number of s ources for a number of air pollution control reasons, the future cost of a coal switch coul d be potentially cost prohibitive. For this45 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 visibil ity impairment values for the Cla ss 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 op tion cost of $4517.00 /ton SO2 removed

Unit Description: Three Coal-fired Boilers, using low sulfur east ern 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 we re considered for the abovementioned Fuel Burning Installation unit (single common stack):

Low sulfur Coals

Wet Scrubbers

Bowater evaluated switching to a lower su lfur (0.6%) western sub-bituminous coal and

determined that is not a viabl e option due to the different ph ysical 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, switc hing to lower sulfur western co al is not so much a cost factor as it is a technologically infeasible factor.

Bowater also evaluated installing SO2 wet sc rubbers which is technically possible, but determined that is an expens ive 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 faci lity 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 re duce operations and thus actual SO2 emissions. They also contends that the VI STAS 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. Bo water 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 mont hs of lowest coal firing correspond to
the months with the worst 20% visi bility (June through September).

Bowater states that the remain ing 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, Bowate r believes that the older 1950 vintage machines may be permanen tly shut down in the future. These less efficient machines require more hot water fr om the boilers to be produced. If they are shut down, less coal will be burned and le ss 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 sc arcity 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 pe rmit limits coal sulfur content to 1.25%, however, actual sulfur content has averaged ne arly 1.0% over the la st three years.

INVISTA evaluated switching to a lower su lfur (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 fr om 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 remo ved. 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 th e 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 ap proximately $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 techni cally feasible as a control option. However, this option could result in an overall ash w ith 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. Th e 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 Extr act 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 techni cally feasible as a control option. However, this option could result in an overall ash w ith properties so different from the current48 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 emissi ons 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 SU MMARY 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 Identified49 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 electricit y 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 pow er boilers that constitute the bulk of its facility SO2 emissions. Bowater presente d 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 th is 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 determi nation that additional SO2 reductions at Bowater Newsprint will not be required fo r 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-ju stifiable as the co st 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 num ber 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 sulfu r fuel costs were more finite in the next review period. TDEC-APC notes that 2018 pred icted visibility impai rment 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 deferr ing fuel switching in this current review period.

EPA Findings : Tennessee has appropriately addresse d this provision. TDEC concluded, based on their evaluation of these companies’ analyses, that no fu rther controls were warranted. After reviewing TDEC’s met hodology and analyses, EPA finds Tennessee’s conclusions acceptable. Regarding the fuel switching option evaluated for INVISTA, while the $1,225 /ton of SO 2 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 consid eration of additional controls to the next assessment period. EPA also finds that all cu rrently available contro l technologies at the time of analysis and applicable to these faciliti es were evaluated fully in terms of the four reasonable progress factors, and the State cons istently 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 SO 2 emissions. This involved identification of ex isting controls on applicable emission units, potential control options for a pplicable emissions, and the su ccessful application of the four factors to determine the feasibility of c ontrols that constitute d reasonable progress.51 III. Evaluation of State Re gional Haze Submittal C. Long-Term Strategy C.4. Enforceability of Reas onable Progress Measures: The plan needs to provide

enforceable emissions limitations and sche dules for compliance for each newly adopted

measure needed to achieve th e 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 Re gional 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-eligib le 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 la rge, older emission sources for additional cont rols 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 revise d final rule, including Appendix Y to 40 CFR Part 51, the Guidelines for BART Determ inations Under the Regional Haze Rule (hereinafter referred to as the “BART Guidelin es”) 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 th e 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 vi sibility 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 qual ity environmental impac ts of compliance, (3) any existing pollution cont rol 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 fr om the use of such technology.

Pages 60-61 The following is a list of fa cilities with BART-eligible sour ces in Tennessee. TDEC-APC developed this list by examining the 2002 NEI data summary. The lis t was electronically

sorted to retrieve sources t hat 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 co mpounds 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 emi ssion 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 elect ronically 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 Mine ral 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 (T VA) – Bull Run Fossil Plant Tennessee Valley Authority (TVA ) – Cumberland Fossil Plant Zinifex Weyerhaeuser Corporation (now Domt ar Paper Company) - Sullivan County

The BART-eligible sources were identifie d using the methodology in the BART
Guidelines.

• One or more emissions units at the faci lity fit within one of the 26 categories
listed in the BART Guidelines 2 ;

2 List of BART Source Categories. The BART requirement only ap plies to sources in specific categories listed in the Clean Air Act. These categories are: (1) Fo ssil-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) Pr imary lead smelters, (18) Fuel conversion plants, (19) Sintering plants, (20) Second ary metal production facilities, (21) Chemical process plants, (22) Fossil-fuel boilers of more than 250 mill ion BTUs per hour heat input, (23) Petroleum storage and transfer facilities with a capacity exceeding 300,000 barrels, (24) Ta conite ore processing facilities, (25) Glass fiber processing plants, and (26) Charcoal production facilities.54 • The emission unit(s) were in exis tence on August 7, 1977 and began operation at some point on or after August 7, 1962; and

• The limited potential emissions from all em ission units identified in the previous two bullets emission units were greater t han 250 tons or more per year of any of these visibility-impairing po llutants: SO2, NOx, and PM 10

.

The BART Guidelines recommend addressing th ese visibility-impairing pollutants: SO 2 , NO

x , and particulate matter, and suggest that States use their best judgment in determining whether to address VOC or a mmonia emissions. TDEC-APC addressed SO2 and NOx, and used particulate matter le ss than 10 microns in diameter (PM 10

) 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 th at VOCs and ammonia from point sources are not visibility-impairing pollutants. Fo r this reason TDEC-APC did not evaluate emissions of VOCs. However, ammonia emissi ons 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 Re gional Haze Submittal D. Best Available Retrofit Technology (BART) Requirements D2. Modeling or other Demonstrat ions 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 violat e 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 cont ribute to visibility im pairment in a Class I area. In accordance with the BART guidelin es, 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 eviden ce 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 re garding individual source impacts upon Class
I areas. In accordance with the Guidelin es, a contribution thre shold of 0.5 deciviews was used for determining which sources were subject to BART.

Tennessee initially identified sixteen (16) fac ilities 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 bo ilers located at the facility have been dismantled. Additionally, Intertrade Holdings, Inc. has permanently shut down the acid plant that was determined to be BART-e ligible (a reduction of sulfur dioxide of approximately 374 tons per year). Holston Army Ammunition Plant has requested a permit limit of 249 tons per yea r 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 pe r year on February 25, 2008 (See Appendix L-12, pages 3-4). The subject acid plant consists of eight sour ces, 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 poten tial emissions above 250 TPY at this facility were either built before August 1962 or were built or modi fied 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 info rmation 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 Mine ral 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 (T VA) – Bull Run Fossil Plant Tennessee Valley Authority (TVA ) – Cumberland Fossil Plant Zinifex57 Figures from Appendix L

Fi gure 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 comple te 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 c onducted using the VISTAS modeling protocol, VISTAS CALMET screening 12-km regional domain, and the old IMPROVE equation. No significant adverse comments we re received during the public comment period.

Table 7.5.2-1. BART Exemption Modeling Re sults for Sources using Old IMPROVE Equation – 12 Km. CALMET

F

acility Class 1 Areas Distance To
Class I Area Impact (Change in58 (km) dv)

DuPont – Humphreys County (for SO 2 , NOx, and PM 10

) 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 PM 10

) Mingo Wildlife Refuge 218 0.151
Sipsey Wilderness Area 216 0.147

Lucite International (for SO 2 , NOx, and PM 10

) Mingo Wilderness Area 187 0.053
Sipsey Wilderness Area 253 0.040

Owens Corning (for SO 2 , NOx,and PM 10

) Mammoth Cave NP Mingo Wildlife Refuge Sipsey Wilderness Area 297

187

200 0.045

0.064

0.040

PCS Nitrogen (for SO 2 , NOx, NH 3 and PM 10

) Mingo Wildlife Refuge 186 0.166

Sipsey Wilderness Area 253 0.074

Zinifex – Clarksville (for SO 2 , NOx, and PM 10

) 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 pr otocol, VISTAS CALMET refined 4-km resolution (domain 3), and the old IMPROVE equation (PCA and TVA).

Table 7.5.2-2. BART Exemption Modeling Re sults for Sources using Old IMPROVE Equation – 4 Km. CALMET

F

acility Class 1 Areas Distance To
Class I Area (km) Impact (Change in dv)

TVA – Bull Run Fossil Plant (for PM 10

) Cohutta Wilderness Area 118 0.126 Great Smoky Mountains

NP 48 0.445

Joyce Kilmer-Slickrock

WA 63 0.226

Linville Gorge Wilderness

A rea 200 0.063

Mammoth Cave National

Park 209 0.033

Shinning Rock WA 131 0.081 Packaging Corp. of America (for SO 2 , NOx and PM 10 ) Mammoth Cave National

Park 299 0.10159 Mingo Wilderness Area 273 0.064 Sipsey Wilderness Area 100 0.247

Table 7.5.2-3 represents the f our (4) facilities that were not able to demonstrate exemption from BART based on the VISTAS mode ling protocol. These sources are subject to the BART controls modeling demonstrations.

Table 7.5.2-3. Modeling Determination Results for BART-Subject Sources

F

acility Class 1 Areas Distance To
Class I Area (km) Impact (Change in dv)

Alcoa – South Plant (1)
(for SO 2 , NOx, and PM 10

) (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 PM 10

) (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)
(PM 10

for SO 2 , NOx, and

P

M 10

)(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 PM 10

) (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-1 st to 8 th -high value, 3% sulfur coal using New Improve Equation.

(2) Alcoa exemption modeling, screening 4-km runs, 1 st highest value, using Old Improve Equation only for MACA.

(3) DuPont BART base case Mammoth Cave (MACA) mode ling with New Improve Equation, refined 4-km runs, 8 th highest value (occurs only 7 days in 2003 at 24 hour maximum firing rate). A ma ximum 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 su mmer time 24-hour maximum emission rates resulted in a 0.474 DV at MACA. This source is s till subject to BART control assessment.

(4) Eastman BART control case, refined 4-km runs, 8 th highest value, SDA/FF Controls, using New Improve Equation.

(5) TVA-Cumberland BART base case, refined 4-km runs, 8 th 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 Se lective 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 i ndividual 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 a ffected BART-eligible EGU to install, operate, and maintain BART for SO2 or NOx emissions. Given th at all BART-eligible units are installing scrubbers and NOx contro ls, 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 allowe d to submit BART exemption modeling demonstrations for PM emissions only. T VA-Bull Run demonstrated that it does not contribute to visibility impai rment 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 visibili ty 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 th e refined 4-km CALMET resolution and one source used the new improve equation in e fforts to demonstrate exemption. For further details about the BART exemption mode ling, please refer to Appendix L.

CALPUFF MODELING

TDEC-APC chose to perform s ource-specific analyses to de termine which sources cause or contribute to visibility impairment using the CALPUFF model. The CALPUFF modeling protocol used for de termining which fac ilities 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 fi nd evidence that an exemption threshold less

than the 0.5 deciview threshold should be us ed. Appendix H’s main document describing reasonable progress has additional informati on in Section 5.0 regarding individual source impacts upon Class I areas. In a ccordance 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 Stat es to include SO2, NOx, and direct particulate matter (PM) emissions, including both PM 10 and PM 2.5 , in determining whet her sources cause or contribute to visibility im pairment. Tennessee used its best judgment and sensitivity modeling to determine that VOC and amm onia emissions did not have an impact on visibility in their Class I ar eas and state. The results show that the maximum impact from eliminating all point source VO C emissions in the VISTAS 12 km domain is less than a 0.5 dv for all Class I areas in the VISTAS dom ain. 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 cont rolling VOCs from a BART source would be much less

than the 0.5 dv threshold. VISTAS and the St ate of Tennessee concl ude that VOCs from61 point sources are not a visibility impairi ng pollutant for BART purposes and that BARTeligible sources do not need to consider VOC emissions.

Removal of the large NH3 emission sources re sults in minimal impact on visibility at Class I areas in the VISTAS region. At thei r discretion states may ask those few large sources to evaluate NH3 impacts and potenti al controls for NH3. Based on the CMAQ sensitivity analyses of the im pact of ammonia emissions, the State determined that only one large TN source of ammonia emissions, PC S Nitrogen, would be required to evaluate those emissions for BART purposes. PCS Nitroge n 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 th ese emissions were included in the PCS Nitrogen BART determination modeling.

Justification of 0.5 dv contribution thre shold 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, “State s remain free to use a threshold lower than 0.5 deciviews if they concl ude that the location of a large number of BART-eligible sources within the State and in proximity to a Class I area justif y 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 sma ller 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 impercep tible amount), their to tal impact would be 10 dv (which can be expected to be quite perceptible). 3 The point remains that multiple sources can cause a larger im pact than a single source. Fo r 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 column62 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 M ountains 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 deve loped and provided the technical analyses to suppor t the BART assessment provisio n for the non-CAIR sources. However, Tennessee opted to have CAIR satisfy BART for SO 2 and NO

x for affected CAIR EGUs, as allowed under th e Regional Haze regulations. As explained in Section III.C.1–EPA Findings,, the State’s demonstrati on 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 CALPUFF 4 modeling system was appropriately applied by TDEC-APC in the assessment of visibility impairment in Cl ass 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 sour ce is anticipated to cause or contribute to impairment of visibility in Cla ss I areas. It is important to no te 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., gr eater than 50 KM) applications at Class I areas. There is no preferred model for a ssessing visibility impact under BART. However, it is appropriate for the State of Tennessee to use the CALPUFF modeling system for its BART exemption a nd control determination modeling. The Visibility Improvement State and Tr ibal Association of the Southeast (VISTAS) developed a “Protocol for the App lication of CALPUFF fo r 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 a nd the source-specific modeling protocols

4 Note that our reference to CALPUFF encompa sses 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.htm63 and reports that were developed by the Tennessee specific sources performing BART modeling. The VISTAS BART modeling prot ocol underwent an extensive stakeholder development and review process, that i nvolved EPA, FLMs, industrial sources, trade groups, lawyers and other interested partie s, 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 pr otocols that complied with the VISTAS protocol. EPA Region 4 provided review s and comments on the source-specific protocols and their subsequent exemption modeling reports. The exemption protocols and modeling reports are presented in Appendi x 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, “Dispe rsion Coefficients for Regulatory Air Quality Modeling in CALPUFF. “ A new methodology was used by the VISTAS States to process the mass concentrations from CA LPOST (post-CALPUFF processor) using the new IMPROVE equation so that the BART anal yses could consider both the old and new IMPROVE equations. The U.S. Environmenta l 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 a nd 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 locat ed in other EPA Regions would require consultation with the appropriate regional offi ce. EPA required the State of Tennessee to submit a request to the EPA Regional Admini strator requesting the use of this new methodology for the BART CALPUFF-based modeling. A September 13, 2007 letter justifying the need for th is approach was sent an d approval from the Regional Administrator was provided to the state on October 5, 2007. The methodology and state and Region 4 letters are locat ed 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 w ith the state’s rationale for choosing this threshold value since there ar e 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 threshol d was not warranted since the majority of the visibility impacts were well below 0.5 deci views. Also, even though several sources impacted each Class 1 area, the overall impact s were low from the BART sources, and we have not made any adverse comments on th e use of the CALPUFF VISTAS versions. Note that our reference to CALPUFF encompasses the whole CALPUFF modeling system, including CALMET/CALPU FF/CALPOST and other pre and post processors. The different versions of CALPUFF have corres ponding 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 vers ions of the CALPUFF modeling system are64 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 w ith 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. Brew er, 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 athttp://www.vistassesarm.org/documents/BARTModelingProtocol_rev3.2_31Aug06.pdf

.

6. March 16, 2006 EPA memo from Denni s Atkinson to Kay T. Prince on Dispersion Coefficients for Regulator y Air Quality Modeling in CALPUFF

7. Additional Regional Haze Questi ons - September 27, 2006 Revision . Informal questions and answers developed by EPA Regional Offi ces Workgroup and shared with States and Tribal Agen cies, FLMs and industry stakeholders.

8. Appendix Y to 40 CFR Part 51, the Guidelines for BART Determinations Under the Regional Haze Rule65 III. Evaluation of State Re gional 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 re quired under BART. The implemen tation 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 Se lective 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 i ndividual 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 a ffected BART-eligible EGU to install, operate, and maintain BART for SO2 or NOx emissions. Given th at all BART-eligible units are installing scrubbers and NOx contro ls, 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 allowe d to submit BART exemption modeling demonstrations for PM emissions only. T VA-Bull Run demonstrated that it does not contribute to visibility impai rment in any Class I area.

EPA Findings : Tennessee has not completely a nd appropriately addressed this provision. The State has appropriately iden tified the BART-eligible sources and those sources subject to BART controls. Howeve r, Tennessee opted to have CAIR satisfy

BART for SO 2 and NO

x 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 Re gional Haze Submittal D. Best Available Retrofit Technology (BART) Requirements D.4. Source Specific B ART 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 av ailable and associated emission reductions achievable (unless the State demonstrates th at an emissions trading program or other alternative will achieve greater reasonable prog ress 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 av ailable, (2) the costs of compliance, (3) the energy and non-air quality environmental impacts of compliance, any pollution control equipment in use at the s ource, (4) the remaini ng useful life of the source, and (5) the degree of improvement in vi sibility 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 unabl e to demonstrate a contribution of less

than 0.5 dv at all Class I ar eas within 300 km from thei r BART-eligible sources. These four sources are considered to be “s ubject to BART” and have submitted analyses containing their evaluation of poten tial 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 se lf-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 cond itions 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 inse rted into the facility’s Part 70 Title V Operating Permit as a new applicable require ment. The timing of adding these federally approved permit conditions will be done consistent with th e 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 SI P. Pursuant to Division Rule 1200-3-23- .05, actual operating permits for the sources are presented in Appe ndix L-12. Like the aforementioned permit conditions, these pe rmits will become effective upon USEPA’s final approval of the Tennessee Regional Haze SIP and serve until such time that they67 can be added to the faciliti es’ Part 70 permits as a new applicable requirement as

described above.

For Eastman, BART will include a more stringe nt sulfur dioxide limitation on its boilers

that necessitates the additi on 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 T ennessee’s Regional Haze State Implementation Plan revi sion, sulfur dioxide (SO 2 ) emissions from Boilers 25-29 shall comply with the less stringent of the following limits:

1. 0.20 pounds of SO 2 per million British Ther mal Units (lb/MMBtu) of heat input; or
2. Reduce uncontrolled SO 2 emissions by 92%.

Compliance with these emissi on limits shall be determined on a thirty (30) calendar day rolling average basis as the average emission rate, or average SO 2 reduction, from either eac h boiler individually while combusting coal, or averaged across all of the boilers that are combusting
coal.

Compliance Assurance M onitoring Requirements:

Measurement of SO 2 emissions: SO 2 emissions shall be measured through the use of continuous in-sta ck monitoring for sulfur dioxide, as specified below:

The source owner or op erator shall install, maintain, operate, and submit quarterly reports of exce ss emissions and sulfur dioxide (SO 2 ) removal efficiency (if applicab le) from continuous in-stack monitoring systems for sulfur dioxide (SO 2 ). The sulfur dioxide monitoring systems shall meet all the requirements of 40 CFR 60 Appendices A and B, or 40 CFR Part 75 Appe ndices A and F.

Compliance will be dete rmined on a 30 calend ar day rolling average basis. Each 30 calendar day av erage shall be the average of the valid daily averages during the prev ious thirty (30) calendar days68 Operational requirements for Sulfur Dioxide (SO 2 ) Monitoring Systems : For this fuel burning instal lation 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 th e monitored units during each calendar quarter. Operational availability levels of less than these amounts may be co nsidered the basis for declaring the fuel burning installation in noncompliance with the applicable monitoring requirements, unless the reasons fo r the failure to maintain these levels of operational availability are accepted by the Technical Secretary as being legitimate malfunc tions of the inst ruments. Data recorded during periods of moni toring system breakdown, repairs, calibration checks, and zero and span adjus tments shall not be included in the data averages.

Quality Assurance re quirements for the Sulfur Dioxide (SO 2 ) 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 shal l be conducted as specified in an approved site-specific monitoring pl an. The monitoring plan must be
submitted to the Technica l Secretary at least nine ty (90) days prior to the startup of the control device.

Recordkeeping: All records required to demonstrate compliance
with this condition shall be main tained at the source location and kept available for inspection by the Technical Secretary or his representative. Records shall be ma intained for five (5) years.

For Alcoa, the final BART determination re sulted in an agreed upon limitation of 3% sulfur in the petroleum coke used in the fa cility’s electrode pr oduction operations and thus, used in their aluminum potlines. Alcoa en visions that it will stil l be in operation in 2064. Alcoa will continue to evaluate long-term options for reducing SO2 emissions including pollution controls and process change s. Progress updates on emerging options will be provided to TDEC-APC as pertinent w ith 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. T hose reports may also form the basis for determining whether or not more stringent c ontrols are warranted in the future progress

reviews.

Alcoa BART Permit Condition fo r inclusion into the69 Tennessee Regional Haze SIP

Emission Limitation: No later than five (5) years a fter 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 cont ent of petroleum coke used to make anodes. All records required to demonstrat e compliance with this condition shall
be maintained at the source location and kept available for inspection by the Technical Secretary or his representative. Records s hall be maintained for five (5) years.

For TVA Cumberland Fossil Plant, TDEC-A PC has determined that no additional controls for visibility impairi ng 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 (SO 2 ) emissions from Boilers No. 1 and 2 shall comply with the following limit:

0.5 pounds of SO 2 per million Brit ish 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 M onitoring Requirements:

Measurement of SO 2 emissions: SO 2 emissions shall be measured through the use of continuous in-sta ck monitoring for sulfur dioxide, as specified below:

The source owner or op erator shall install, maintain, operate, and submit quarterly reports of exce ss emissions and sulfur dioxide (SO 2 ) removal efficiency (if applicab le) from continuous in-stack monitoring systems for sulfur dioxide (SO 2 ). The sulfur dioxide70 monitoring systems shall me et 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 main tained at the source location and kept available for inspection by the Technical Secretary or his representative. Records shall be ma intained for five (5) years.

For Dupont Old Hickory, the facility pr oposes limiting the total combined daily emissions for Boilers 20 and 24 based upon the fo llowing operating limits stated below.

Dupont Old Hickory BART Permit C ondition for inclusion into the Tennessee Regional Haze SIP

1. Name of source facility a nd 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: Su lfur dioxide and Nitrogen oxide

2. Specifics of the controls, contro l 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 ox ide emissions from these units by 3,978 pounds/day in the summer and 3,330 pounds/day in the winter.

3. Enforceable emission limitat ions representing BART (40 CFR 51.308(d)(3);(e)).

Allowable emission limitations* Sulfur dioxide Nitrogen oxides (pounds/day) (pounds/day) Summer (May – 32,256 6,12071 September): Winter (October – Ap ril): 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 Com pany, 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 a pproval of Tennessee’s Regional Haze State Implementation Plan revision.

5. A requirement that each sour ce 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 reco rdkeeping 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:

M C20 = Mass of coal burned in Boiler No. 20, tons per day
M C24 = Mass of coal burned in Boiler No. 24, tons per day
V

NG20 = Volume of natural gas burned in Boiler No. 20, 10 6 cubic feet per day
V

NG24 = Volume of natural gas burned in Boiler No. 24, 10 6 cubic feet per day
V

FO20 = Volume of fuel oil burned in Bo iler No. 20, 1,000 gallons per day
V

FO24 = Volume of fuel oil burned in Bo iler No. 24, 1,000 gallons per day
EF C20 = Emission factor for coal burni ng in Boiler No. 20, pounds per ton
EF C24 = Emission factor for coal burning in Boiler No. 24, pounds per ton
EF NG20 = Emission factor for natural gas burning in Boiler No. 20, pounds per 10 6 cubic feet 

### ( )( )( ) ( ) ( )( ) 

### [ ] EL EF V EF V EF M EF V EF V EF M FO FO NG NG C C FO FO NG NG C C ≤

⋅ +

⋅ +

⋅ +

⋅ +

⋅ +

⋅ 24 24 24 24 24 24 20 20 20 20 20 2072 EF NG24 = Emission factor for natural gas burning in Boiler No. 24, pounds per 10 6 cubic feet
EF FO20 = Emission factor for fuel oil burning in Boiler No. 20, pounds per 1,000 gallons
EF FO24 = 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 mu st be retained for at least five years. The source will be requir ed 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 limitati ons are based on a maximum 24-hour standard beginning at midni ght each calendar day. For a more detailed discussion of the afor ementioned BART determinations, please see Appendix L.

Pages L.30-L.57

8.1.1.1 Alcoa - BART-eligible Un its and Existing Control

Alcoa has twenty-four BART-elig ible emission units that co mprise the BART-eligible source. The majority of these units are current ly controlled. A descri ption of these units taken from the Alcoa BART demonstrati on 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, SO 2 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, SO 2 Reactor /

Fabric Filter

05-0008-18 Anode Baking

Furnace This emission unit incl udes the 261N, 262N, and 262S anode baking furnaces, which are controlled by the A-446. PM, SO 2 , NO X Reactor /

Fabric Filter73 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 incl udes 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 in cludes 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, SO 2 Fabric

Filter

05-0008-19 Ball Mill Th is 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 assemblie s 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 Filter74 05-0008-31 Ore Unloading,
Trans. and Storage This emission unit co vers 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 sodastorage 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 ar e 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 incl udes railcar unloading of virgin packing material and storage and transfer of clean and recycled packing material for use in th e 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. Th is 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 Filter75 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 SO 2 and particulate matter (PM), and the anode bake

furnace emits lesser amounts of SO 2 , nitrogen oxides (NO X

), and PM. These three

emission units are already e quipped with sophisticated em ission control equipment for

PM, so the BART determination for these em ission units focuses primarily on potential

reductions for SO 2 and NO X

.

The remaining 21 emission units identif ied in Table 8.1.1.1 are material handling

and transfer operations that support the potli nes 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 c ontrol 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 ma terial handling and transfer operations. Given

the level of emissions and that fabric filters represent the best available control, these

emission sources were excluded from bot h visibility modeling and further BART

engineering analysis. Based on visibility modeling results fo r the aluminum reclamation

melting furnaces, which have a comparable PM emission rate, visibility impacts from

individual fabric filte rs 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-eligi ble Units and Existing Control

MSOP PES Vent ID Emission Unit NOx SO276 Table 8.1.1.2 shows the list of BART-eligible units that are loca ted at Tennessee Operations (TNO) in Kingsport, TN. This tabl e includes general information on the size and emissions of th e emission units. Specific information on stack parameters and maximum daily emissions of the emission un its 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 bo ilers are Combustion Engineering tangentially-fired pulverized c oal boilers started up between 1966 and 1972. They are rated at a maximu m heat input capacity of 655 MBtu/hr. Eastern Kentucky and we stern Virginia type bituminous coal is the only fuel burned in these units (other than natural gas for startups).

These units are used for co-produc tion of steam and electricity in support of manufacturing operation s at the Kingsport plant. A high level of reliability and the abi lity 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 Scrubbers77 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 precipita tor (ESP) with collecting area of 167,416 ft2 and a design flue gas flow rate of 286,000 acfm. The electrostatic precipitators are locate d 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 Al stom 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 th at provide for flame attachment closer to the burners. When fir ed 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 l oad. 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 sign ificantly 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 l oad demands dictated by unplanned outages or site steam load requirements. For a given control strategy, this assumption will resu lt in higher estimates of emission reductions and correspondingly lowe r 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 di oxide 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 millio n Btu/hr; installation date- 1968; tangentially fired; primary fuel- coal; #1 standby fuel- natural gas; #2 standby fuel- No.2 Fuel Oil78 • Boiler 24- Rated capacity- 315 millio n 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 li mitations- 24 hrs/day, 8,760 hr/year

• Boiler 20 (Emission Point 009) mass emission standards:

Pollutant Lb/hr Lb/day Rolling 12 Month

Tons

PM 10 77.4 1858 339.1

SO 2 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

PM 10 54.8 1315 240.1

SO 2 916.9 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 co ntent of any solid or liquid fuel to 2.0% sulfur by weight. The above st andards are based on a maximum sulfur content of 0.05% by wei ght 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 Pl ant 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 em issions 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 Control79 The TVA Cumberland Fossil Plant (CUF), lo cated in Stewart County, TN, has two pulverized-coal-fired steam generators that ar e 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 (SO 2 ) control, selective catalytic reduction systems for controlling nitrogen oxides (NO

x ), 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 Cl ean Air Interstate Rule (CAIR). Based on guidance from EPA and TDEC-APC, compliance w ith CAIR satisfies BART requirements for SO 2 and NO

x emissions at electric generating un its. As a result, the BART analysis only considerd PM 10 emissions.

Table 8.1.1.4 .1 Stack Parameters for CUF

Table 8.1.1.4.2. Emissions profiles from SM OKE 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 0.010 7 1 0.010 7

22001 PM2

_ 5 PSO4 0.119 1 0.119

Table 8.1.1.4.3 Emission Rate s 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 ( o K) 321 32180 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 vi sibility 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 Determinat ion Analysis

Section 169A(g)(7) of the CAA re quires 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 compli ance, (3) Any existing pollution control technology in use at the source, (4) The rema ining 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 fact ors are to be considered, according to the BART guidelines states have flexibility in how the factors are weighted in making their determinations regarding w hat constitutes BART. (See 70 FR 39170, 1 st col., July 6, 2005.)81 

### 8.3.1 Control Scenarios Considered

Each facility reviewed several potential cont rol alternatives. These control alternatives

considered and the associated visibility improvement that would result are summarized inTables 8.3.1.1 through 8.3.1.6 below taken from the Alcoa, Eastman Chemical, TVACumberland, and DuPont-Old Hickory BART de termination submitta ls respectively.

Table 8.3.1.1 Alcoa - SO 2 Post-Control Emission Rates a

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 po tline primary control system, th e potline roof emissions, and the anode bake furnace.

b Compared with current poten tial 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 0.26782 w/ Wet Scrubbers)

Table 8.3.1.3 Eastman BART Evaluatio n 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 0.5683 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 Ev aluation 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 & 24 0.605 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% Natura l 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 Equation85 Table 8.3.1.6 – DuPont-Old Hickor y – MACA Visibility Assessment Summary of the Control Scenario Vi sibility & 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 Av erage 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

SO 2 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

Co firin g o n B ot h B o il e r s 740 169 $14

, 190

, 215 493 $28

, 759 -0.369 3.69 1.80 1.1686 

### 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 submitta l (Appendix L-8). The facility proposed that BART is taking a pollution prevention lim it of 3% sulfur in the calcined petroleum coke used to manufacture anodes.

Table 8.3.2.1 Alcoa - Summary of the Impacts Analysis for SO 2 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 5,234 a $217,000 $39,000 $7,500 33,200 438 tons/year of PM 2.5 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 4,830 687 b 30,400 5,600 8,200 2,800 36 tons/year of PM 2.5 2,300 tons/year of solid waste for disposal c

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 result ing 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 sce narios considered are summarized in Tables 8.3.2.2 and 8.3.2.3 below taken from the Ea stman BART determination permit application submittal (Appendix L-8). The facility proposed that BART is the application of Spray Dryer Absorber with Fabric F iltration (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 Boile rs #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 info rmation. Its large footprint either e liminates it as an option or drives up cost considerably to relocate bu ildings, 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 resulti ng from the control scenario considered of Wet ESP for both boilers r anged 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 theWet ESP are summarized in Tables 8.3.2.4 and 8.3.2.5 below taken from the TVACumberland BART determination permit appl ication 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 C ontrol Cost Manual, Sixth Ed

.

Table 8.3.2.5 Annual Costs for Wet ESP: CUF Unit 1 or 289 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 ft 2 /1000 cfm, 4.5 million cfm Material $ 787,610 1% of PEC

Utilities
Electricity-fan $ 599,342 2" H 2 O ∆ p, $0.06/kWhElectricityoperating $ 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 Ai r Pollution Control Cost Manual, Sixth Ed . Capital recovery factor (CRF) based on 12% intere st rate and 20-yr equipment life.

ForDuPont-Old Hickor y visibility improvement result ing 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 scenario s 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 cont rols are summarized in Table 8.3.2.9 below taken from the DuPont-Old Hickory additi onal submittal letter dated January, 24, 2008. This letter addresses revised cost effectivenes s/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.90Table 8.3.2.6 BART Economic Analysis for DuPont Old Hickory Boilers 20 & 24 at Maximum Combined Daily EmissionsBART For SO2 and NOx for Both Boilers 20 & 24 Based on Maximum Emissions Day for 2005-06SO2 Model Case Identifier-->AFKMH C POJEBoilers 20 & 24Boilers 20 & 24Boilers 20 & 24 Boilers 20 & 24SO2 ECONOMIC PARAMETERSBASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers20 & 24 Boilers 20 & 24 Boilers 20 & 24Boilers 20 & 24using Coal 3 using Coal 2using current CoalFACTORED ESTIMATE FROM RTP DATABASECurrent Coal 1Coal 2Coal 3using Coal 3using Coal 2using current Coalusing current Coal Boiler 20 Only w/Boiler 20 Only w/Boiler 20 Only w/Control Option -->No FGDNo FGDNo FGD95% WSS95% WSS95% WSS50% Gas Cofiring95% WSS95% WSS95% WSSCoal Percent Sulfur-->1.88 1.50 1.00 1.00 1.50 1.881.88 1.00 1.50 1.88A&E Emission Rate, lb/MMBtu -->3.13 2.49 1.66 0.08 0.12 0.163.13 0.08 0.12 0.16SO2 Emission Rate at DHI, lb/hr-->2,3751,895 1,26463 95119 1188 561 8411054Annual SO2 Emissions, TPY-->7,0405,617 3,745187281352 3520 899 13481690Equivalent Annual Average Hourly SO2 Emissions, lb/hr-->1,6071,282 85543 6480 804 205 308386A&E Total Capital Requirement:$63,365,423 $63,365,423 $63,365,423 $35,425,148 $35,425,148 $35,425,148O&M Costs @ 8% + reagent + waste disposal:$7,778,324$7,741,314$16,245,380 $5,001,297 $4,971,689$9,968,709Range:+50/-30+50/-30+50/-30+50/-30+50/-30+50/-30Coal Change Incremental Cost Per Ton vs Baseline:$0 $10$15$15$10$0 $0 $15 $10$0Coal Change Annual Additional Cost :$1,970,962 $2,956,443 $2,956,443$1,970,962$0 $2,956,443 $1,970,962$0Natural Gas Cofiring Incremental Cost Increase:$14,190,215Capital Recovery Costs:$6,957,183$6,957,183$6,957,183 $3,889,491 $3,889,491$3,889,491Total Annual Costs Excluding Coal Change:$14,735,506 $14,698,497 $23,202,562 $8,890,788 $8,861,180$13,858,200Annual Emissions Reduction vs Baseline Current Coal:1,423 3,2956,853 6,7596,688 3,520 6,142 5,6925,351Annual Emissions Reduction vs Coal 2:1,8725,430 5,3365,265 2,097 4,718 4,2693,928Annual Emissions Reduction vs Coal 3:3,558 3,4643,393 225 2,846 2,3972,055Downtime at Gas Fuel Price Difference:$3,317,550$3,317,550$3,317,550 $3,317,550 $3,317,550$3,317,550Amotized Downtime atGas Fuel Price Difference:$364,249 $364,249$364,249$364,249 $364,249$364,249Total Annualized Cost:$1,970,962 $2,956,443 $18,056,198 $17,033,708 $23,566,812 $14,190,215 $12,211,479 $11,196,391 $14,222,449Cost Effectiveness Relative toBaseline Current Coal, $/Ton Removed:$1,385 $897 $2,635$2,520 $3,524 $4,031 $1,988 $1,967 $2,658Cost Effectiveness Relative to Coal 2, $/Ton Removed:$526 $2,962$2,823 $4,102 $5,827 $2,170 $2,161 $3,119Cost Effectiveness Relative to Coal 3, $/Ton Removed:$4,244$4,064 $6,075 $49,997 $3,252 $3,438 $5,482NOx Model Case Identifier-->AB1B2C B D1D2ENOx ECONOMIC PARAMETERSBASELINE+ Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boilers 20 & 24 Boiler 24As-Is & Boiler 24 As-Is & Boiler 24 As-Is &FACTORED ESTIMATE FROM RTP DATABASEusing current Coal Boiler 20 Only w/Boiler 20 Only w/Boiler 20 Only w/Control Option -->CCLNBSNCRLNB+SCR50% Gas CofiringLNBSNCRLNB+SCRNOx Emission Rate at DHI, lb/hr-->42125225250 252324 324 208Annual NOx Emissions, TPY-->1233740740148740843 843 374Equivalent Annual Average Hourly NOx Emissions, lb/hr-->28216916934 169192 192 85A&E Total Capital Requirement:$5,215,728 $3,122,793 $31,225,760 $2,607,864 $1,856,689 $17,355,321O&M Costs:$208,629 $580,742 $1,470,994$104,315$435,205 $816,962Range:+50/-30+50/-30 +50/-30+50/-30+50/-30+50/-30Natural Gas Cofiring Incremental Cost Increase:$14,190,215Capital Recovery Costs:$572,659 $342,866 $3,428,421$286,329$203,854 $1,905,521Total Annual Costs Excluding Downtime Gas Cost:$781,288 $923,608 $4,899,414$390,644$639,059 $2,722,483Annual Emissions Reduction:4934931,085 493391 391 859Downtime at Gas Fuel Price Difference:$1,658,775 $1,658,775 $1,658,775$1,658,775 $1,658,775 $1,658,775Amotized Downtime atGas Fuel Price Difference:$182,125 $182,125 $182,125 $182,125$182,125 $182,125Total Annualized Cost:$963,413 $1,105,732 $5,081,539$14,190,215 $572,769$821,184 $2,904,607Cost Effectiveness Relative to Baseline Current Equipment, $/Ton Removed:$1,953 $2,241 $4,682$28,762$1,466 $2,102 $3,380Incremental Cost Effectiveness Relative to LNB on Boiler 20 Only, $/Ton Removed:$3,803 $5,189 $6,490$132,585$4,974Annual interest rate (fractional):0.07Control system life (years):15Capital recovery factor (system):0.11091Table 8.3.2.7 BART Economic Analysis for DuPont Old Hickory Boiler 20 at Combined Maximum Daily EmissionsSO2 Model Case Identifier-->AFKM H CP O J ECF as annualoperatingrate=80%BASES --->CFas annualaverage % ofmax dailyemissions=92%Coal HHV, Btu/lbAs-Received=11,428 Per Boiler MMBtu/hr = 445Per Boiler SCFM=107,453Natural Gas PriceDifferential Over Coal,$/MMBtu=$6.00SO2 ECONOMIC PARAMETERSBASELINE+ Coal 2 Coal 3 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20 Boiler 20FACTORED ESTIMATE FROM RTP DATABASECurrent Coal 1 using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using current CoalControl Option -->No FGDNo FGDNo FGD85% SDA+FF95% WSS85% SDA+FF95% WSS85% SDA+FF95% WSS50% Gas CofiringCoal Percent Sulfur-->1.88 1.50 1.00 1.00 1.00 1.50 1.50 1.88 1.88 1.88A&E Emission Rate, lb/MMBtu -->3.13 2.49 1.66 0.25 0.08 0.37 0.12 0.47 0.16 3.13SO2 Emission Rate at DHI, lb/hr-->1391 1110 740 111 37 166 55 209 70 695Annual SO2 Emissions, TPY-->5632 4494 2996 449 150 674 225 845 282 2816Equivalent Annual Average Hourly SO2 Emissions, lb/hr-->1286 1026 684 103 34 154 51 193 64 643A&E Total Capital Requirement:$52,388,658 $35,425,148 $52,388,658 $35,425,148 $52,388,658 $35,425,148O&M Costs @ 8% + reagent + waste disposal:$5,057,064 $5,001,297 $5,019,522 $4,971,689 $10,010,512 $9,968,709Range:+50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-30Coal Change Incremental Cost Per Ton vs Baseline:$0 $10 $15 $15 $15 $10 $10 $0 $0 $0Coal Change Annual Additional Cost :$0 $1,576,779 $2,365,168 $2,365,168 $2,365,168 $1,576,779 $1,576,779 $0 $0Natural Gas Cofiring Incremental Cost Increase:$11,352,241Capital Recovery Costs:$5,751,993 $3,889,491 $5,751,993 $3,889,491 $5,751,993 $3,889,491Total Annual Costs ExcludingCoal Change:$10,809,057 $8,890,788 $10,771,515 $8,861,180 $15,762,505 $13,858,200Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3:$4,245 $3,124 $4,639 $3,198 $7,328 $5,106Annual Emissions Reduction vs Baseline Current Coal:1,138 2,636 5,183 5,482 4,958 5,408 4,787 5,351 2,816Annual 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 1808 Weeks Downtime at Gas Fuel Price Difference:$3,317,550 $3,317,550 $3,317,550 $3,317,550 $3,317,550 $3,317,550Amotized Downtime at Gas Fuel Price Difference:$364,249 $364,249 $364,249 $364,249 $364,249 $364,249Cost Effectiveness Relative to Baseline Current Coal:$1,385 $897 $2,612 $2,120 $2,564 $1,998 $3,369 $2,658 $4,031Cost 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 $49,997NOx Model Case Identifier-->ABBC B DD ENOx ECONOMIC PARAMETERSBASELINE+ Boiler 20 Boiler 20 Boiler 20 Boiler 20FACTORED ESTIMATE FROM RTP DATABASEusing current CoalControl Option -->CCLNBSNCRLNB+SCR50% Gas CofiringA&E Emission Rate, lb/MMBtu -->0.542 0.325 0.325 0.065 0.325NOx Emission Rate at DHI, lb/hr-->241 145 145 29 145Annual NOx Emissions, TPY-->977 586 586 117 586Equivalent Annual Average Hourly NOx Emissions, lb/hr-->223 134 134 27 134A&E Total Capital Requirement:$2,607,864 $1,856,689 $17,355,321O&M Costs:$104,315 $435,205 $816,962Range:+50/-30 +50/-30 +50/-30Natural Gas Cofiring Incremental Cost Increase:$11,352,241Capital Recovery Costs:$286,329 $203,854 $1,905,521Total Annual Costs:$390,644 $639,059 $2,722,483Cost Effectiveness w/o Gas Cost:$1,000 $1,636 $3,168Annual Emissions Reduction:391 391 859 3914 Weeks Downtime at Gas Fuel Price Difference:$1,658,775 $1,658,775 $1,658,775Amotized Downtime at Gas Fuel Price Difference:$182,125 $182,125 $182,125Overall Cost Effectiveness:$1,466 $2,102 $3,380 $29,059ESTIMATE USING USEPA REFERENCESLOW LNBSNCRLNB+SCREmission Rate, lb/MMBtu -->0.54 0.325 0.325 0.065Total Capital Requirement:$400,500 $1,112,500 $2,562,142O&M Costs:$44,500 $222,500 $199,674Range:LOW HIGH NACapital Recovery Costs:$43,973 $122,147 $281,309Total Annual Costs:$88,473 $344,647 $480,983Annualinterestrate(fractional): 0.07Cost Effectiveness:$226 $882 $560C ontrolsystemlife(years): 15Annual Emissions Reduction:391 391 859C apitalrecoveryfactor(system ):0.110BART FOR SO2 & NOX BOILER # 20 BASED ON MAXIMUM EMISSIONS DAY FOR 2005-0692Table 8.3.2.8 BART Economic Analysis for DuPont Old Hickory Boiler 24 at Maximum Combined Daily EmissionsSO2 Model Case Identifier-->AFKM H CP O J ECF as annualoperatingrate=20%BASES --->CFas annualaverage % ofmax dailyemissions=33%Coal HHV, Btu/lbAs-Received=11,428 Per Boiler MMBtu/hr = 315Per Boiler SCFM=81,478Natural Gas PriceDifferential Over Coal,$/MMBtu=$6.00SO2 ECONOMIC PARAMETERSBASELINE+ Coal 2 Coal 3 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24 Boiler 24FACTORED ESTIMATE FROM RTP DATABASECurrent Coal 1 using Coal 3 using Coal 3 using Coal 2 using Coal 2 using current Coal using current Coal using current CoalControl Option -->No FGDNo FGDNo FGD85% SDA+FF95% WSS85% SDA+FF95% WSS85% SDA+FF95% WSS50% Gas CofiringCoal Percent Sulfur-->1.88 1.50 1.00 1.00 1.00 1.50 1.50 1.88 1.88 1.88A&E Emission Rate, lb/MMBtu -->3.13 2.49 1.66 0.25 0.08 0.37 0.12 0.469 0.156 3.13SO2 Emission Rate at DHI, lb/hr-->985 786 524 79 26 118 39 148 49 492Annual SO2 Emissions, TPY-->1408 1123 749 112 37 169 56 211 70 704Equivalent Annual Average Hourly SO2 Emissions, lb/hr-->321 256 171 26 9 38 13 48 16 161A&E Total Capital Requirement:$41,319,616 $27,940,275 $41,319,616 $27,940,275 $41,319,616 $27,940,275O&M Costs @ 8% + reagent + waste disposal:$3,522,056 $2,777,027 $3,512,670 $2,769,625 $7,018,208 $6,276,670Range:+50/-30 +50/-30 +50/-30 +50/-30 +50/-30 +50/-30Coal Change Incremental Cost Per Ton vs Baseline:$0 $10 $15 $15 $15 $10 $10 $0 $0 $0Coal Change Annual Additional Cost :$0 $394,183 $591,274 $591,274 $591,274 $394,183 $394,183 $0 $0Natural Gas Cofiring Incremental Cost Increase:$2,837,974Capital Recovery Costs:$4,536,672 $3,067,692 $4,536,672 $3,067,692 $4,536,672 $3,067,692Total Annual Costs Excluding Coal Change:$8,058,727 $5,844,719 $8,049,342 $5,837,317 $11,554,880 $9,344,362Cost Effectiveness for Scrubbing w/o Gas Cost vs Coal 3:$12,659 $8,215 $13,868 $8,426 $21,488 $13,771Annual Emissions Reduction vs Baseline Current Coal:285 659 1,296 1,371 1,240 1,352 1,197 1,338 704Annual 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 45Downtime at Gas Fuel Price Difference:$0 $0 $0 $0 $0 $0Amotized Downtime at Gas Fuel Price Difference:$0 $0 $0 $0 $0 $0Cost Effectiveness Relative to Baseline Current Coal:$1,385 $897 $6,676 $4,696 $6,812 $4,610 $9,655 $6,986 $4,031Cost 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 $49,997NOx Model Case Identifier--> A B B C BNOx ECONOMIC PARAMETERSBASELINE+ Boiler 24 Boiler 24 Boiler 24 Boiler 24FACTORED ESTIMATE FROM RTP DATABASEusing current CoalControl Option -->CCLNBSNCRLNB+SCR50% Gas CofiringA&E Emission Rate, lb/MMBtu -->0.57 0.342 0.342 0.068 0.342NOx Emission Rate at DHI, lb/hr-->180 108 108 22 108Annual NOx Emissions, TPY-->257 154 154 31 154Equivalent Annual Average Hourly NOx Emissions, lb/hr-->59 35 35 7 35A&E Total Capital Requirement:$2,607,864 $1,266,104 $13,870,439O&M Costs:$104,315 $145,537 $654,032Range:+50/-30 +50/-30 +50/-30Natural Gas Cofiring Incremental Cost Increase:$2,837,974Capital Recovery Costs:$286,329 $139,011 $1,522,900Total Annual Costs:$390,644 $284,548 $2,176,931Cost Effectiveness w/o Gas Cost:$3,803 $2,770 $9,634Annual Emissions Reduction:103 103 226 103Downtime at Gas Fuel Price Difference:$0 $0 $0Amotized Downtime at Gas Fuel Price Difference:$0 $0 $0Overall Cost Effectiveness:$3,803 $2,770 $9,634 $27,632ESTIMATE USING USEPA REFERENCESLOW LNBSNCRLNB+SCREmission Rate, lb/MMBtu -->0.57 0.342 0.342 0.068Total Capital Requirement:$283,500 $787,500 $2,063,784O&M Costs:$31,500 $157,500 $157,419Range:LOW HIGH NACapital Recovery Costs:$31,127 $86,463 $226,592Total Annual Costs:$62,627 $243,963 $384,011Annualinterestrate(fractional): 0.07Cost Effectiveness:$610 $2,375 $1,699C ontrolsystemlife(years): 15Annual Emissions Reduction:103 103 226C apitalrecoveryfactor(system ):0.110BART FOR SO2 & NOX BOILER # 24 BASED ON MAXIMUM EMISSIONS DAY FOR 2005-069394 Table 8.3.2.9 DuPont-Old Hickory BART Co ntrol 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 Bo ilers 20 & 24 E. LNB Plus SCR on Boiler 20 Only

C. LNB Plus SCR on Both Boilers 20 & 24

B3. Current Coal with 50% Natura l 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 Cont rol Determination–Proposed Emission

Limitations Operating Limits SO2 (lb/day) NOx (lb/day) Summer Months (May-September) 32260 6120 NON-Summer Months (October -April) 38570 677095 8.3.3 Energy and Non-air Quality Impacts

For Alcoa , a wet scrubber removes SO 2 by forcing the exhaust gas through a spray

tower or absorber where it contacts water dr oplets 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 sc rubber. 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 to tal 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 electricit y per year. A wet scrubber on the anode bake furnace would add 2,800,000 kW-hours per yea r. 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 we t 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 w ill 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 disc harge, 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 th e community and therefore also have an environmental impact due to power producti on 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 en vironmental 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 stream s 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 reductio n in remaining life). Since the SDAs would be placed before the partic ulate 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 estim ated this loss of flyash sa les at 11,000 tons per year and

that this volume would shorte n the landfill life by an additiona l 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 additiona l energy (natural gas) and raw materials to produce the cement along with the associated air emissions. It w ould also result in an increased price of concrete. The loss of l andfill space due to eith er of these reasons (calcium sulfate sludge or loss of flyash sales) should not cause a direct environmental96 impact as the landfill has liners and leac hate 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 Ho lston River. However, once the landfill is full, a new one will have to be sited, likely furt her from Eastman's facility. Inevitably, a new landfill will result in loss of natural hab itat 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 wh ich would require disc harge to the South Fork Holston River (SFHR) through an NPDE S permitted outfall. The salts in this blowdown stream would be comprised of s odium sulfate (99.5 %), sodium fluoride (0.4 %), and sodium chloride (0.06 %). The volu me of the discharge is expected to be approximately 0.5 MGD. Under normal ope rating conditions the blowdown would

increase Eastman's Total Di ssolved Solids (TDS) loading to the river by approximately 238,000 lb/day.

The worst-case maximum TDS loading could in crease by as much as 351,000 lb/day. The SFHR immediately downstream of Eastman and th e city of Kingsport is classified for use as an industrial water supply by the Tennessee Department of Environment and

Conservation. Due to this cl assification, an ambient water quality criterion of 500 mg/L TDS applies in this reach of the river. Base d on the three most recent years of quarterly data, the current average ambient TDS con centration downstream of Kingsport is 196 mg/L. Under normal scrubber blowdown disc harge conditions and average river flow, the discharge of the scrubber blowdown w ould result in an increase in TDS of approximately 17 mg/L downstream of Kingsport. Therefore, due to the blowdown discharge, the average TDS concentration downs tream 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-cas e 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 maxi mum projected increase in loading (351,000 lb/day) discharged by the scrubber, and th e maximum simultaneous discharge of TDS from all area point sources. This worst-cas e 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 re sult in an exceedence of the 500 mg/L water quality criterion even under worst-case conditions.

For TVA-Cumberland , the energy costs associated w ith 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 on97 both units at CUF would consume over 16 bi llion gallons per year of additional water and require treatment of an equiva lent volume of wastewater.

For DuPont – Old Hickory , this analysis does not prov ide detailed quantification of energy and non-air quality environmental impacts for each compliance option since this is a high level analysis. However, thos e impacts and be described qualitatively.

Use of lower sulfur alone coal would not en tail any significant change s 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 conditi on by the quantity of calcium sulfite/sulfate formed in the scrubber. This can be estimated based on removal percent and expected calcium/sulfur stoichiome tric ratio. Costs for that disposal are

included within the estimated O&M cost esti mates. 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 scr ubber and baghouse, including, for example, lime transport, slurry preparati on and injection, baghouse pulse air, ash and spent sorbent handling, and increased fan power to compensate fo r increased flue gas pressure drop. Increased purchased electric ity would result in in creased emissions of

SO 2 , NOx, CO 2 , and other emissions from the electri c utility generators providing that power, which could in fact, be units that th emselves impact Class I areas with their SO 2 and NOx emissions. Water would also be consumed for slurry preparation.

Use of a sodium wet scrubber would require us e of caustic as the reagent. Liquid waste disposal would increase for disposal of the scrubber blowdown stream. The existing plant waste water treatment fa cility likely does not have ade quate capacity for that waste stream directly, but some form of neutraliza tion 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, fo r 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 SO 2 , NOx, CO 2 , and other emissions from the electric utility generators providi ng that power, which could in fact, be units that themselves impact Cl ass I areas with their SO 2 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 im pact 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 in creased unburned carbon would result in

incremental increase in coal consumption and the associated electricity fo r pulverization and fan power, as well as increase d 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 with98 either control technology. Ammonia slip reac ts with sulfur and chloride species in the flue gas forming ammonium salts which increa se the concentration of fine particulates (PM2.5) in the flue gas, potentially increasi ng stack opacity. On-site storage of ammonia would create its own set of safety issues. Di sposal 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 syst em of fluid-bed reactor type system with fabric filtration downstream of the reacto r beds (Potlines 1 and 2, and Anode Baking Furnace). The rest of the BART subject un its are controlled by fabric filteration.

For Eastman Chemical , existing controls on the BART s ubject sources are described in Table 8.1.1.2 (above). There are no existing add -on SO2 controls fo r 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. Cracki ng furnaces are natural-gas fired only. General Purpose Batch Chemical Manufactu ring (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 pul verized-coal-fired steam generators that are considered BART eligible. Units 1 and 2 ar e nominally rated at about 1325 MW each. Both units are equipped with flue gas desu lfurization (FGD) systems for sulfur dioxide (SO 2 ) control, selective catalytic reduction sy stems for controlling nitrogen oxides (NO

x ), 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 Cl ean Air Interstate Rule (CAIR). Based on guidance from EPA and TDEC-APC, compliance w ith CAIR satisfies BART requirements for SO 2 and NO

x 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 follo wing permit limitations:

• Boilers 20 and 24 are subject to MCL 10.56.200 (Davidson County-Local Program) which limits the maximum sulfur co ntent of any solid or liquid fuel to 2.0% sulfur by weight. The above st andards are based on a maximum sulfur content of 0.05% by wei ght 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 th e 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 earlie r for each facility.

8.4 Final BART Determination

After reviewing the proposed BART determin ations 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 Eastm an Chemical is the application of SDA/FFdry flue-gas desulfurization using a Spray Dr yer Absorber (SDA) followed by a fabric filter for the five C oal-fired Boilers #25-#29 (B-253).

TDEC-APC concluded that BART for TVA-Cu mberland 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 operatin g limits stated in

Table 8.4 below.

Table 8.4 DuPont-Old Hickory BART Contro l Determination–Emission Limitations Operating Limits SO2 (lb/day) NOx (lb/day) Summer Months (May-September) 32260 6120 NON-Summer Months (October -April) 38570 6770100 TDEC-APC plans to notice draf t permits after approval of the Tennessee Regional Haze SIP by EPA and issue final permits as expedi tiously as possible but no later than five years after the date of the SIP approval. The pe rmits will be issued following Tennessee’s standard permitting process. The BART specifi c permit conditions for those sources are included as Appendix L-12.

EPA Findings Tennessee has appropriately addr essed 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 iden tification of existing controls on applicable emission units, potential contro l options for applicable emission precursors, and the successful application of the Fi ve Factors to determine the f easibility 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 guid ance to these sources.101 III. Evaluation of State Re gional 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 incl ude 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 sour ce subject to BART be required to install and operate BART as expeditious ly as practicable, but in no ev ent later than 5 years after approval of the implementation plan revision and a requirement that each source subject

to BART maintains the cont rol 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 inse rted into the facility’s Part 70 Title V Operating Permit as a new applicable requirem ent. The timing of adding these federally approved permit conditions will be done consis tent with the permit reopening provisions of the Tennessee rules that im plement 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 A ppendix L-12. Like the aforementioned permit conditions, these pe rmits will become e ffective upon USEPA’s final approval of the Tennessee Regional Ha ze 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 subs equently be added to the appropriate Part 70 permits. Tennessee has appropriately addressed this provision.102 III. Evaluation of State Re gional Haze Submittal E. Coordination of Regional Haze and RAVI Requirements The State must revise its plan to provide fo r 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 th e data from these measurements, but is not responsible for the funding decisi ons to maintain these measurem ents 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 scat tering, operated by the National Park Service at Look Rock, TN.

• A Tapered Element Oscillating Microbal ance (TEOM) for continuously measuring

PM 2.5 mass concentration, operated by the Natio nal Park Service at Look Rock, TN.

In addition, TDEC-APC and the local air agencies in the State operate a fairly comprehensive PM 2.5 network of the filter based Fe deral reference method monitors, continuous mass monitors (TEOMs) and filter ba sed speciated monitors. A map of the

various locations around the State is included in Figure 9.0.1. These PM 2.5 measurements help TDEC-APC characterize air pollution level s in areas across the state, and therefore aid in the analysis of visibility impro vement in and near the Class I areas.

The IMPROVE measurements are central to Te nnessee’s regional haze monitoring strategy, and it is difficult to visualiz e how the objectives listed abov e could be met without the monitoring provided by IMPROVE. Any reducti on 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 ne twork 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 proces s information from its own measurements at about the same pace and with the same a ttention 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 a ccess to the IMPROVE data and data analysis103 tools. TN is encouraging VISTAS and the ot her 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 accordan ce with the requirements liste d in Section 51.308(f) of the federal rule for regional haz e, 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 pe riodic reports evaluating progress towards the reasonable progress goals establ ished for each mandatory Class I area. In accordance with the requirements listed in Section 51.308(g) of th e federal rule for regional haze, TDEC-APC commits to subm itting 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 reasonabl e progress report will evaluate the progress made towards the reasonable progress goal for each mandatory Cl ass I area located within Tennessee and in each mandatory Cla ss 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, St ep 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 nonattainme nt areas as well as the prevention of significant deterioration will address emissi ons 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 require d for sources that are subject to the new source review regulations.

Page 93
Consultation TDEC-APC also commits to ongoing cons ultation with the FL Ms throughout the implementation process, including annual disc ussion 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 a ny 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 outsi de the boundary of the mandatory Class I Federal area. Visibility in any mandatory Cl ass 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 experi encing RAVI, nor are any of its sources104 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 rema ins unchanged as do the previously approved PSD/NSR visibility provisi ons (July 18, 1996 at 61 FR 3538 7). EPA finds that this regional haze submittal appropriately suppl ements and augments Tennessee’s RAVI visibility provisions to address region al 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 implemen tation 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 51.3 08(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 reasonabl e 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 Cl ass I area located outside Tennessee which may be affected by emissions from within Te nnessee. In addition, consistent with the monitoring provisions for RAVI and re gional haze under 40 CFR 51.305 and 40 CFR 51.308(d)(4), Tennessee will rely on the IMPR OVE 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 a ny 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 rulema king (April 21, 2010, 75 FR 20783).105 III. Evaluation of State Re gional Haze Submittal F. Monitoring Strategy and Ot her Implementation Requirements Monitoring Strategy: The plan must include a monitoring strategy for measuring, characterizing, and reporting of regional haze visi bility impairment that is representative of all mandatory Class I Federal areas w ithin 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 al so provide for the following:

A. The establishment of any additional monitoring sites or equipment needed to assess whether reasonable progress goal s 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 da ta 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 haz e monitoring strategy must necessarily be based on, or dir ectly comparable to, IMPROVE. The IMPROVE measurements provide the onl y long-term record availabl e for tracking visibility improvement or degradation and therefore Te nnessee 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 Stat e. 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 Pa rk and Joyce Kilmer – Slickrock Wilderness Area, both of which lie partly in Te nnessee 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 th e data from these measurements, but is not responsible for the funding decisi ons to maintain these measurem ents 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 scat tering, operated by the National Park Service at Look Rock, TN.

• A Tapered Element Oscillating Microbal ance (TEOM) for continuously measuring

PM 2.5 mass concentration, operated by the Natio nal Park Service at Look Rock, TN.

In addition, TDEC-APC and the local air agencies in the State operate a fairly comprehensive PM 2.5 network of the filter based Fe deral reference method monitors, continuous mass monitors (TEOMs) and filter ba sed speciated monitors. A map of the

various locations around the State is included in Figure 9.0.1. These PM 2.5 measurements help TDEC-APC characterize air pollution level s in areas across the state, and therefore aid in the analysis of visibility impro vement in and near the Class I areas.

Figure 9.0.1 PM2.5 Monitoring Network in Tennessee107 The IMPROVE measurements are central to Te nnessee’s regional haze monitoring strategy, and it is difficult to visualiz e how the objectives listed abov e could be met without the monitoring provided by IMPROVE. Any reducti on 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 ne twork 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 proces s information from its own measurements at about the same pace and with the same a ttention 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 a ccess to the IMPROVE data and data analysis tools. TN is encouraging VISTAS and the ot her 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 Re gional 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 invent ory 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 i nventory 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 commitm ent to update the inventory periodically.

State Regional Haze Submittal Pages 19, 23, 49, 93 The Regional Haze Rule at 51.308(d) (4) (v) re quires a statewide emissions inventory of pollutants that are reasonably anticipated to ca use or contribute to visibility impairment in any mandatory Class I area. An inven tory was developed for the baseline year 2002 and projected to 2009 and 2018. The pollutants inventoried include volatile organic compounds, nitrogen oxides, fine particulate (PM 2.5

), coarse particulate (PM 10

), 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 sour ce classifications: stationary point and area sources, off-road and on-road mobile sources, and biogenic sources. Stationary point sources are those sources that emit gr eater than a specified tonnage per year, with data provided at the facility level. Electric generating util ities and industrial sources are the major categories for stationary point sour ces. Stationary area sources are those

sources whose individual emissi ons are relatively sm all, but due to the large number of these sources, the collective emissions from th e source category could be significant (i.e., dry cleaners, service stations, agricultural sour ces, 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, ai rcraft, etc. The emissions from these sources, like stationary area sources, ar e 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 esti mated 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 c ountywide level.

In addition to the various source classifications , there are also various types of emission inventories. The first is the actual base yea r inventory. This inventory is the base year emissions that correspond to the meteorologica l data used, which for this modeling effort is data from 2002. These emissions are us ed for evaluating th e air quality model performance.

The second type of inventory is the typical bas e year inventory. This inventory is similar to the actual base year inventory, except that for sources whose emissions change109 significantly from year to year, a more typica l emission value is use d. In this modeling effort, typical emissions were developed fo r the electric generating units (EGUs) and the wildland fire emissions. The air quality m odeling is run using the typical base year inventory and the future year inventory. The re sults from these two runs are then used to calculate relative reduction factors. These rela tive 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 bas eline 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 in ventory and discussion of the methodology is contained in Appendix D. The emissions summa ries for other VISTAS states can also be found in Appendix D.

Table 4.1.6-1 2002 Actual Base G4 (B&F) E missions 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) Em issions 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 Inve ntories 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 co mplete inventory and discussion of the methodology is contained in Appendix D.

Table 7.2.3-1. 2009 Base G4 (B&F) Emi ssions 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- R oad Mobil e 55,358 86,641 5,557 5,877 48 5,651 Biogenics 894,214 18,081 0 0 0 0110 TOTAL 1,294,377 399,425 94,340 288,059 45,228 357,780

Table 7.2.3-2. 2018 Base G4 (B&F) Emi ssions 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 pl ans for EGUs compared to the control assumed in the modeling.

... Analysis of emission changes over the 5-yea r period, identified by source or activity;

... All requirements listed in 51.308(g) shall be addressed in th e SIP revision for reasonable

progress.

There are several technical improvements that are recommended in the emissions inventory and air quality mode ls 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 n ext long term strategy.

EPA Findings : Tennessee has appropriately addressed this provision.111 IV. Conclusion Except for those aspects of the Regional H aze 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 pr ogress goals for each of its Class I areas, determining Best Available Retrofit T echnology (BART), and submitting a long-term strategy that addresses regiona l 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