Proposed BART Determination for Eastman Chemical Company's 

Tennessee Operations in Kingsport, Tennessee 

TABLE OF CONTENTS 

1.0 Introduction 

2.0 BART-Eligible Units at TNO 

3.0 BART Control Options Review and Analysis (Steps 1 – 4) 

3.1 Building 253 Powerhouse, Coal-fired Boilers #25-#29 

3.2 Building 83 Powerhouse, Coal-fired Boiler #24 

3.3 Building 6C Cracking Furnaces #27 and #28 

3.4 OC-Batch (Batch Manufacturing) 

4.0 Visibility Impacts Analysis (Step 5) 

5.0 Proposed BART Determinations 

6.0 Proposed Permit Conditions and Compliance Schedule 

Attachment 1 - Capital Cost Estimates 

Attachment 2 - Annual Operating/Maintenance Costs Summary 

Attachment 3 – Unit Cost Table 

Attachment 4 – Design Parameters 

Attachment 5 - Modeling Protocol 

Enclosure (CD ROM with modeling files)

Pre-Hearing Draft

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Appendix L.8 - 303

January 18, 2008
1.0 Introduction 

Pursuant to 40 CFR 51.308, Tennessee is required to submit to the U.S. Environmental Protection 

Agency (EPA) a state implementation plan (SIP) revision to address the requirements in 40 CFR 

51.308(e) – Best Available Retrofit Technology (BART) requirements for regional haze visibility 

impairment. The Tennessee Division of Air Pollution Control (TDAPC) has identified Eastman 

Chemical Company's (Eastman) Tennessee Operations (TNO) facility in Kingsport, Tennessee as 

a BART-eligible source. Based on the Q/D (tons per year/km from Class I areas) for the TNO 

facility and the results of Calpuff screening runs, Eastman has determined that its BART-eligible 

emission units will not be exempt from the required Case-by-Case BART Analysis. Accordingly, 

the purpose of this document is to present Eastman's proposed Best Available Retrofit Technology 

(BART) determinations to the Tennessee Division of Air Pollution Control (TDAPC) for inclusion 

in Tennessee's SIP revision submittal. 

This submittal follows the Guidelines for BART Determinations Under the Regional Haze Rule 

found in 40 CFR Part 51 Appendix Y. 

Those Guidelines outline five basic steps of a Case-by-Case BART Analysis: 

 STEP 1- Identify All Available Retrofit Control Technologies 

 STEP 2 - Eliminate Technically Infeasible Options 

 STEP 3 - Evaluate Control Effectiveness of Remaining Control Technologies 

 STEP 4 - Evaluate Impacts and Document Results 

The impact analysis in Step 4 is to consist of four parts: 

 Part 1 – Costs of compliance 

 Part 2 – Energy impacts 

 Part 3 – Non-air quality environmental impacts 

 Part 4 – Remaining useful life 

 STEP 5 - Evaluate Visibility Impacts 

 

2.0 BART-Eligible Units at TNO 

Since TNO is in the chemical process plant category, the facility is a subject to BART. 

Accordingly, Eastman has reviewed its emission inventory and identified those emission units that 

are "BART-eligible". An emission unit is BART-eligible if it was "in existence on August 7, 1977 

but was not "in operation" before August 7, 1962 and it emits a visibility-impairing pollutant (and 

all such emission units at the facility collectively have the potential to emit more than 250 tons per 

year of any one visibility-impairing pollutant). "Visibility-impairing pollutant" as defined by the 

Visibility Improvement State and Tribal Association (VISTAS) include particulate matter, sulfur 

dioxide and oxides of nitrogen. VISTAS has advised that emissions of volatile organic 

compounds and ammonia not be subject to BART. 

Table 1 shows the list of BART-eligible units as defined above that are located at TNO. Table 1 

includes general information on the size and emissions of the emission units. Specific information 

on stack parameters and maximum daily emissions of the emission units is included in the BART 

Modeling Protocol submitted by Eastman to the TDAPC on July 26, 2006 (included as 

Attachment 5). 

Eastman BART Submittal Page 1 of 34 

February 27, 2007 

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Appendix L.8 - 304

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Table 1 

Eastman TNO BART-eligible Emission Units 

NOx 

2005 Actual Emissions 2005 Actual Emissions 

MSOP PES Vent ID Emission Unit 

Description 

Tons Basis 

Allowable Existing 

Controls 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 

02 B-83-1 C Boiler 24 (overfeed 

stoker, 500 MBtu/hr) 

569 CEMS N/A None 1,494 Fuel 

Usage, Sulfur Content 

Cracking Furnaces (Natural Gas-Fired) 16 B-6C-1 A Furnace 27 (18 

MBtu/hr) 

6.5 AP-42, 

Fuel Usage 

10.6 tpy None 0.16 AP-42, 

Fuel Usage 

16 B-6C-1 B Furnace 28 (18 

MBtu/hr) 

6.5 AP-42, 

Fuel Usage 

10.6 tpy None 0.16 AP-42, 

Fuel Usage 

Others 25 OCBATCH Various (see 

Title V application) 

General Purpose Batch Chemical Manufacturing 

14.0 tpy Scrubbers 

Eastman BART Submittal Page 2 of 34 

February 27, 2007 

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
3.0 BART Control Options Review and Analysis 

3.1 Building 253 Powerhouse, Coal-fired Boilers #25-#29 

3.1.1 Emission Unit Description 

These five boilers are located side-by-side in Building 253 at the Kingsport 

plant. All of these boilers are Combustion Engineering tangentially-fired 

pulverized coal boilers started up between 1966 and 1972. They are rated at a 

maximum heat input capacity of 655 MBtu/hr. Eastern Kentucky and western 

Virginia type bituminous coal is the only fuel burned in these units (other than 

natural gas for startups). 

These units are used for co-production of steam and electricity in support of 

manufacturing operations at the Kingsport plant. A high level of reliability and 

the ability to handle boiler load swings are requirements for any emissions 

control system. Although these units are typically base loaded, at times 

individual boiler load can swing as much as 100 klb/hr in a minute or two in 

response to a steam or electric load upset. 

Existing Particulate Matter Controls: Each boiler has a five field electrostatic 

precipitator (ESP) with collecting area of 167,416 ft2 and a design flue gas flow 

rate of 286,000 acfm. The electrostatic precipitators are located at ground level. 

These precipitators were installed in the early 1990s. 

Existing NOx Controls: During 2001-2003, the burners on these boilers were 

retrofitted with the Alstom P2 system. This system incorporates vaned closecoupled overfire-air (separates the upper end auxiliary air from the fire creating 

a mini-SOFA within the windbox) with modified coal tips that provide for flame 

attachment closer to the burners. When fired in low NOx mode during the NOx 

SIP call ozone season (May through September), average NOx emission rates 

have run around 0.32 lb/MBtu. However, performance depends on boiler load. 

At high boiler loads, three mills operation is required. At lower loads, the boiler 

can run on only two mills. This latter mode of operation is, in essence, 

equivalent to a NOx control strategy know as Burner Out of Service (BOOS) 

and results in significantly lower NOx emissions. For our evaluations of further 

NOx control measures, we are assuming an average emission rate of 0.35 

lb/MBtu to account for uncertainty in future boiler load demands dictated by 

unplanned outages or site steam load requirements. For a given control strategy, 

this assumption will result in higher estimates of emission reductions and 

correspondingly lower cost-effectiveness estimates. 

Existing SO2 Controls: Other than purchase of low to medium sulfur coal to 

meet the SIP limit of 2.4 lb/MBtu, there are no existing controls of sulfur 

dioxide emissions. The average emission rate for calendar year 2005 was 1.4 

lb/MBtu. 

Eastman BART Submittal Page 3 of 34 

February 27, 2007 

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Appendix L.8 - 306

January 18, 2008
3.1.2 Step 1: Identify Available Retrofit Emission Control Techniques: 

Particulate matter: These boilers are equipped with highly efficient electrostatic precipitators (ESPs) for control of particulate matter emissions. The Title 

V permit requires periodic performance tests. The results of the most recent 

tests and the estimate of actual emissions for calendar year 2005 are shown 

below: 

Table 2 – B-253 Particulate Emissions 

Boiler 

ID 

2005 Heat Input (MBtu) Date of Most 

Recent Test 

Particulate Matter 

Emissions 

(lb/MBtu) 

2005 Actual 

Particulate Matter 

Emissions (tons) 

25 4,603,268 6/29/2004 0.0108 25 

26 4,624,689 6/21/2005 0.0097 22 

27 4,193,784 5/17/2005 0.0039 8 

28 4,390,794 6/6/2002 0.0047 10 

29 4,215,942 8/22/2001 0.0145 31 

These boilers are subject to the Industrial Boiler Maximum Achievable Control 

Technology (MACT) standard for industrial boilers (40 CFR 63 Subpart 

DDDDD). This rule sets a PM emission standard for existing large solid fuel 

units of 0.07 lb/MBtu. EPA's BART guidance states that "in many cases, it will 

be unlikely that States will identify emission controls more stringent that the 

MACT standards without identifying control options that would cost many 

thousands of dollars per ton. Unless there are new technologies subsequent to 

the MACT standards which would lead to cost effective increases in the level of 

control, you may rely on the MACT standards for purposes of BART." (70 FR 

39164). Eastman believes BART is equal to MACT for these boilers for the 

following three reasons: 

1. These boilers' emission rates are far below the applicable MACT standard. 

2. The MACT standard is very recent (September 13, 2004) and no new 

proven technologies have emerged since this recent date. 

3. It is obvious by engineering judgement that the cost to replace the existing 

ESPs or to install add-on controls such as a bag filter would be costprohibitive since actual emissions are so small (ranging from 8 to 31 tons 

per year). 

Additionally, beyond the MACT comparison, there is a New Source 

Performance Standard applicable to boilers of this size and type if they were 

constructed today. That limit is 0.03 lb/MBtu (ref. 40 CFR 60.43b(a)(1)). 

Eastman BART Submittal Page 4 of 34 

February 27, 2007 

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Appendix L.8 - 307

January 18, 2008
Nitrogen oxides 

Eastman has identified the technologies listed in Table 3 below as available 

retrofit technologies for its B-253 pulverized coal boilers (#25-#29): 

Table 3 – B-253 NOx Available Retrofit Technologies 

Technology Description 

Year-round LNB Run existing low-NOx burners in 

low-NOx mode year-round 

SOFA Separated overfire air 

SOFA/SNCR Selective Non-Catalytic 

Reduction added to a SOFA 

system 

SCR Selective Catalytic Reduction 

NGR Natural Gas Reburn 

Sulfur Dioxide 

Eastman has identified the technologies listed in Table 4 below as available 

retrofit technologies for its B-253 pulverized coal boilers (#25-#29). Note, 

technologies that achieve lower control efficiencies are not shown. 

Table 4 – B-253 SO2 Available Retrofit Technologies 

Technology Description 

SDA/ESP Semi-dry flue-gas desulfurization 

using a spray dryer absorber 

(SDA) ahead of existing ESP 

SDA/ESP-FF Conversion Semi-dry flue-gas desulfurization 

using a SDA ahead of existing 

ESP converted to a fabric filter 

Caustic Scrubbers Spray tower absorbers using a 

water/caustic (sodium hydroxide) 

solution to absorb sulfur dioxide 

Dual-alkali Sodium hydroxide spray tower 

absorbers with a system using 

hydrated lime to regenerate the 

sodium hydroxide and uses a 

thickener, a clarifier, and a belt 

filter to produce a calcium sulfate 

sludge for landfill. 

LSFO Wet flue-gas desulfurization 

using limestone scrubbing with 

forced oxidation (LSFO) process 

3.1.3 Step 2: Eliminate Technically Infeasible Options 

NOx Control Technologies: Of the technologies listed in section 3.1.2 for 

reduction of NOx, the only one Eastman contends may be technically infeasible 

is SCR. To our knowledge, SCR has yet to be installed on an industrial coalfired boiler responding to steam load swings such as those experienced at our B253 boilers. These boilers can have a steam load reduction of 100,000 pounds 

per hour over a one minute period. These steam load swings are accompanied 

by significant flue gas temperature changes. SCR is a post-combustion (“addon”) pollution control device that requires ammonia injection (or urea) and a 

specific flue gas temperature range for optimum performance. In addition, 

Eastman BART Submittal Page 5 of 34 

February 27, 2007 

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Appendix L.8 - 308

January 18, 2008
because of the load-following nature of industrial boilers, there is the possibility 

of excess ammonia slip from the SCR, increasing overall annual operating costs 

and causing potential operational and environmental impacts. 

Nevertheless, for comparison purposes, we have provided cost-effectiveness 

calculations in section 3.1.4 below for SCR. As will be shown, SCR, even if it 

were technically feasible, will not be reasonably cost-effective. 

SO2 Control Technologies: Dual alkali was developed in the 1970s, but was 

never widely used as utilities opted for LSFO or fuel changes to meet Acid Rain 

requirements. Eastman has found only one dual alkali system in operation at a 

coal-fired boiler. While vendors may advertise it as a technology they offer, 

they cannot point to any recent sales or give references of facilities that operate 

this technology. This limited use results in a high amount of risk that this 

technology can be successfully deployed. Eastman notes, however, that the 

footprint for this technology is very large (it employs a lime prep system, large 

diameter thickeners (70 feet) and clarifiers (48 feet) and a 42 foot long belt 

filter) and two redundant systems would be required. There is inadequate space 

adjacent to the B-253 Powerhouse for this system without major relocation of 

buildings, railroad tracks, and ash ponds. Although these features would 

eliminate this technology as a practical matter, we have obtained cost estimates 

for its use and those are presented below. 

3.1.4 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

Eastman determined control effectiveness of the available technologies through 

a series of interactions with equipment and technology suppliers. The 

conclusions are shown in Tables 5 and 6 below: 

Table 5 – B-253 NOx Available Retrofit Technologies – Control 

Effectiveness 

Technology Description Performance 

Year-round LNB Run existing low-NOx burners in 

low-NOx mode year-round 

This operational change should 

achieve an annual average 

emission rate of 0.35 – 0.4 

lb/MBtu 

SOFA Separated overfire air Some form of separated overfire 

air, either boosted or non-boosted 

should achieve an annual average 

emission rate of 0.28 lb/MBtu 

SOFA/SNCR Selective Non-Catalytic 

Reduction added to a SOFA 

system 

Several vendors supply SNCR 

systems. SNCR, combined with 

SOFA should achieve about a 

50% reduction from the 0.35 

baseline, or an annual average 

emission rate of 0.17 lb/MBtu 

SCR Selective Catalytic Reduction SCR should achieve an 80% 

reduction, or an annual average 

emission rate of 0.07 lb/MBtu 

NGR Natural Gas Reburn NGR should achieve a 45% 

reduction, or an annual average 

emission rate of 0.19 lb/MBtu. 

Eastman BART Submittal Page 6 of 34 

February 27, 2007 

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Appendix L.8 - 309

January 18, 2008
Table 6 - B-253 

SO2 Available Retrofit Technologies – Control Effectiveness

Technology Description Performance 

SDA/ESP Dry flue-gas desulfurization 

using a spray dryer absorber 

(SDA) ahead of existing ESP 

Reduction efficiency limited to 

65-71%. 

SDA/ESP-FF Conversion Dry flue-gas desulfurization 

using a SDA ahead of existing 

ESP converted to a fabric filter 

Conversion of the ESP to a FF 

should allow SDA to achieve the 

NSPS standard of 0.2 lb/MBtu or 

92% reduction, burning low 

sulfur coal. 

Caustic Scrubbers Spray tower absorbers using a 

water/caustic (sodium hydroxide) 

solution to absorb sulfur dioxide 

Caustic scrubbers should achieve 

the NSPS standard of 0.2 

lb/MBtu or 92% reduction, 

burning low sulfur coal, with 

capability of achieving 95% 

reduction with medium and high 

sulfur coals. 

Dual-alkali Uses sodium hydroxide spray 

tower absorbers with a system 

using hydrated lime to regenerate 

the sodium hydroxide and uses a 

thickener, a clarifier, and a belt 

filter to produce a calcium sulfate 

sludge for landfill. 

Dual alkali using caustic 

scrubbers should achieve the 

NSPS standard of 0.2 lb/MBtu or 

92% reduction, burning low 

sulfur coal, with capability of 

achieving 95% reduction with 

medium and high sulfur coals. 

LSFO Wet flue-gas desulfurization 

using limestone scrubbing with 

forced oxidation (LSFO) process 

LSFO should achieve the NSPS 

standard of 0.2 lb/MBtu or 92% 

reduction, burning low sulfur coal 

with capability of achieving 95% 

reduction with medium and high 

sulfur coals. 

 3.1.5 Step 4: Evaluate Impacts and Document the Results 

Part 1 Impacts Analysis (Costs) 

Eastman has prepared budgetary cost estimates (accuracy of plus 50% or minus 

25%) for the above technologies based on vendor estimates and professional 

estimators experienced in projecting total project costs for projects completed at 

the TNO facility. Eastman notes these types of cost estimates prepared before 

even preliminary engineering is completed warrant relatively high contingency 

factors. As cost estimates are refined, these contingency factors decrease, but, it 

is our experience that the final cost estimates increase along with the increased 

engineering detail. Eastman notes that, while these capital cost estimates are in 

2006 dollars, construction costs for industrial projects of this nature involving 

heavy use of steel, stainless steel, and boilermaker labor are escalating at 

unprecedented rates and actual construction costs are expected to be 

significantly higher by the time these projects would be implemented. 

For each technology, Eastman has estimated the duration of an extended outage 

that would be required to tie-in each technology. Some technologies can be 

installed during a normal annual maintenance outage. Others require several 

more weeks to complete. For these, Eastman has estimated it would incur 

$88,000 increased operating costs per week to allow for purchase of additional 

Eastman BART Submittal Page 7 of 34 

February 27, 2007 

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Appendix L.8 - 310

January 18, 2008
power from the grid and to idle a standby natural gas boiler. The capital cost 

estimate details are shown in Attachment 1. 

Projected annual operating and maintenance costs are shown in Attachment 2. 

The unit costs assumed are shown in Attachment 3. Current raw material price 

quotations have been obtained and standard incremental costs (again, specific to 

the TNO facility) for utilities such as power, steam, inert gas, river water, etc 

have been used. Reagent costs are important factors in the overall cost analysis. 

For these, Eastman's Procurement personnel have performed market research to 

arrive at our best forecast for lime, limestone, and caustic. Annual maintenance 

costs are assumed at three percent of capital. Only the sulfur control systems are 

projected to require additional operating personnel. 

These costs estimates have been made based on defined design parameters for 

each technology. The key design parameters are shown in Attachment 4. 

Eastman has used a capital recovery factor based on equipment life of 15 years 

and an interest rate of 8.5 percent. This interest rate is representative of the cost 

of capital for chemical manufacturers. 

Nitrogen Oxides 

Summary level data for each of the NOx reduction technologies evaluated for B253 are shown in Table 7 below: 

Table 7 – NOx Costs Effectiveness Summary (5 Boilers) 

Technology Capital 

Cost 

$M 

Annual O/M 

Cost 

$M 

Assumed 

Percent 

Control 

Efficiency 

Annual 

NOx 

Reduced 

(tons) 

CostEffectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

Year Round 

LNB 

-- $0.3 M 36%* 905 $365 -- 

SOFA $3.8 M - 

$16.0 M 

$0.144 M-

$0.78 M 

20%** 757 $792-$3,565 -- 

SNCR $8.0 M-

$24.0 M 

$5.42 M - 

$6.37 M 

51%-56%** 1947 – 

2110 

$3,278 - 

$4,384 

$4,863 (vs 

SOFA) 

SCR $96.3 M $10.4 M 80%** 3030 $7,240 $8,488 -

$9,415 (vs. 

SOFA) 

NGR $15.2 M $28.1 M 45%** 1700 $17,619 $16,495 (vs. 

SOFA) 

* During non-ozone season only 

**Percent reductions beyond Year Round LNB 

As stated above, the B-253 boilers are currently equipped with low NOx 

burners. However, during periods outside the NOx SIP Call Trading Program, 

these boilers are not operated in the low-NOx control mode. This allows for 

lower loss on ignition (LOI) levels in the flyash such that a significant amount 

(around 11,000 tons per year) can be sold to the concrete industry. Running in 

the low-NOx mode also causes a loss of boiler efficiency of around 0.5 percent 

which is equivalent to about an extra 3,500 tons of coal that must be burned each 

year to generate the same output. Eastman's evaluation shows that solely on a 

direct cost basis, it may be reasonable and cost-effective to operate these boilers 

in the low-NOx mode year-round. The main direct cost would be forfeiture of 

the flyash sales plus additional landfill costs and loss of boiler efficiency. 

However, as will be discussed in Part 3 (Non-air Quality Impacts) and in Section 

Eastman BART Submittal Page 8 of 34 

February 27, 2007 

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Appendix L.8 - 311

January 18, 2008
4 (Visibility Impacts), Eastman questions that this technology should be 

employed outside of the ozone season. 

EPA's BART guidance establishes a presumptive NOx emission limit of 0.28 

lb/MBtu for tangential-fired utility boilers greater than 200 MW burning 

bituminous coal. TNO's B-253 boilers, rated for 655 MBtu/hr, or roughly 65 

MW, are much smaller than these. Nevertheless, Eastman evaluated the use of 

SOFA technologies to achieve this presumptive level, but our analysis has 

concluded that probable detrimental effects to the operation and mechanical 

integrity of the boiler are likely. Chief among these technical concerns is further 

starving the lower portions of the furnace of combustion air and subsequent 

increases in LOI. Any further increase in LOI during low NOx control mode 

will lead to conditions such as increased slagging and fouling in the backpass 

areas of the boiler (economizer and air preheater) or possibly to serious safety 

risks such as air preheater fires and precipitator fires. B-253 already experiences 

these conditions using the current low NOx control strategy, and additional 

overfire air will only serve to exacerbate these effects. Further reductions in 

primary airflow necessary to boost overfire air volume will also reduce the 

flame detachment from the P2 burner tips which can cause problems ranging 

from destruction of the tips to coal feed pipe fires. Due to the diminutive size of 

the furnace in B-253 boilers as compared to large utility units, residence time in 

the furnace is reduced giving less time for complete combustion of the coal. It is 

therefore not technically correct to extrapolate NOx reduction results commonly 

obtained in utility boilers to the small furnaces at B-253. Therefore, while 

Eastman has evaluated the potential cost-effectiveness of SOFA technology for 

the B-253 boilers, we are not convinced it is feasible to meet the 0.28 lb/MBtu 

presumptive limit applicable to utility boilers on a continuous basis without 

putting these critical boilers at undue risk of forced outages. Also, as will be 

discussed, the visibility improvements (see Section 4) that could be gained from 

using this technology do not warrant this expense or this increased risk to the 

reliable operation of the boilers. 

Table 7 shows a wide range in potential costs of a SOFA system. The low side 

of the range is represented by a SOFA system that does not utilize a new fan to 

boost the overfire air flow. The high side of the range includes the cost of a 

booster fan and larger ductwork. This large difference in costs translates also to 

the costs of a SNCR system, one of which would couple with a non-boosted 

SOFA system and the other with a boosted SOFA system. Detailed and costly 

computational fluid dynamics modeling would be required to determine which 

of these systems would be required to meet the presumptive limit. Therefore, 

we have shown the range of costs, but Eastman cautions it is not possible to 

conclude at this time that the lower cost option would be sufficient. In any 

event, Eastman concludes (as discussed above) the use of this technology results 

in undue risk to the boilers given the potential visibility benefits. 

Eastman also evaluated technologies that could potentially achieve NOx 

emission rates below the presumptive level. These included NGR, SNCR and 

SCR. The average cost-effectiveness of all of these is well above levels deemed 

reasonable under the Clean Air Interstate Rule and is well above current NOx 

credit market values. Also, as stated above, Eastman does not believe SCR has 

been proven to be technically feasible on industrial boilers subject to rapid load 

swings such as our B-253 boilers. Also, the SNCR options we investigated 

incorporate a SOFA system to help obtain good mixing in the furnace in order to 

obtain the expected removal efficiencies, and so SNCR would have the same 

drawbacks as SOFA as noted above. 

Eastman BART Submittal Page 9 of 34 

February 27, 2007 

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Appendix L.8 - 312

January 18, 2008
Sulfur Dioxide 

Summary level data for each of the sulfur dioxide reduction technologies 

evaluated for B-253 are shown in Table 8 below: 

Table 8 – SO2 Costs Effectiveness Summary (5 Boilers) 

Technology Capital 

Cost 

$M 

Annual O/M 

Cost 

$M 

Assumed 

Percent 

Control 

Efficiency 

Annual 

SO2 

Reduced 

(tons) 

CostEffectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

SDA/ESP $97.8 M $6.1 M 71% 10,815 $1,649 -- 

SDA/ESP-FF 

Conversion 

$139.1 M $7.9 M 92% 13,930 $1765 $2,185 (vs. 

SDA/ESP) 

Caustic 

scrubbers 

$87.8 $8.1 M 95% 14,385 $1,295 $410 vs. 

SDA/ESP 

Dual alkali* $106.8 M $7.1 95% 14,385 $1,009 $857 (vs. 

SDA/ESP) 

LSFO $185.8 M $7.7 M 95% 14,385 $2,085 $3,533 vs 

SDA/ESP or 

$12,775 (vs. 

SDA/ESP-FF 

Conversion) 

*Dual alkali provided for information. Its large footprint either eliminates it as an option or drives up 

cost considerably to relocate buildings, railroad tracks, ash ponds, etc. Also, its use has been 

extremely limited and Eastman's confidence that it can be successfully operated is low. 

EPA very recently (February 27, 2006) updated the New Source Performance 

Standard (NSPS) for sulfur dioxide emissions from coal-fired industrial boilers. 

This standard is found at 40 CFR 60.42b(k) and is stated as either 0.2 lb/MBtu 

or 92 percent reduction. Given that this NSPS is so new, Eastman believes it 

represents the best level of control these sources could reasonably install as 

BART. As stated in the February 27, 2006 Federal Register, this standard 

recognizes the technical difficulties of facilities firing inherently low sulfur fuels 

such as the Eastern bituminous coals Eastman utilizes from Eastern Kentucky 

and Southwest Virginia coal mines. 

Eastman's evaluation of Spray Dryer Absorber (SDA) technology concludes that 

it would be reasonable to install SDA on the B-253 boilers with a resulting 

annual average emission rate of 0.2 lb/MBtu or 92 percent control. In order to 

meet this emission reduction goal using our current regionally available coal 

supply, Eastman believes it will be necessary to convert the existing ESPs to 

baghouses. All but a few coal-fired boilers equipped with SDA have a baghouse 

following the SDA, rather than an ESP. The baghouse provides for additional 

reaction time for the conversion of SO2 to calcium sulfate due to the buildup of 

an ash cake on the filter bags. Eastman's own experience with SDA followed by 

an ESP on our Boiler 30 has shown this operation to be problematic due to 

temperature limitations on the ESP inlet and lime deposits on the ESP internal 

components. This need to retrofit the ESPs will add substantially to the project 

cost. However, the incremental cost compared to the SDA/ESP is somewhat 

close to the average cost effectiveness, so Eastman concludes the additional 

expense to retrofit the ESP to a baghouse is reasonable, if the associated 

visibility improvement warrants it. 

Although not shown here, we did evaluate adding the SDA and a new baghouse 

downstream of the ESP. However, this is a more costly alternative for the same 

removal efficiency. This latter option was further complicated by a larger 

Eastman BART Submittal Page 10 of 34 

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January 18, 2008
footprint and either the need for new stacks or long duct runs to tie back into 

existing stacks. 

Eastman has also identified wet-FGD using sodium hydroxide (i.e. caustic) as an 

option to achieve the NSPS benchmark. This technology would employ large 

20 feet diameter by 50 feet tall open spray towers with three levels of spray to 

control sulfur dioxide emissions. For medium and high sulfur content coals, this 

technology has the potential capability to control sulfur dioxide by greater than 

95 percent. However, we note that we have yet to find a coal-fired boiler 

equipped with a caustic scrubber that achieves 95 percent control on a 

continuous basis. Use of this technology would require new stacks mounted on 

top of the spray towers. Also, the flow through the ESP would have to be 

reversed and the induced draft fan made larger and relocated downstream of the 

ESP. While caustic scrubbing is not a new technology and is in widespread use, 

its application to coal-fired boilers is limited. For this reason Eastman's 

acceptance of this technology is conditional and will be based on the outcome of 

a detailed engineering study to determine its technical feasibility for B-253. 

Subsequently, assuming the visibility improvements associated with this 

technology as applied to B-253 are warranted (see discussion in Section 4 

below), Eastman believes caustic scrubbers to be a reasonable option, along with 

SDA (as discussed above) to achieve the NSPS benchmark. 

Finally, Eastman did evaluate wet-FGD (limestone scrubbing with forced 

oxidation – or LSFO) as an option to achieve the NSPS benchmark. The 

performance of LSFO in controlling SO2 would be similar to caustic scrubbing 

discussed above. However, LSFO generally is used for units much larger than 

Eastman's boilers and is most commonly used where high sulfur coals are 

burned. From EPA's review of the NSPS standard, they determined that no 

industrial boilers were found to use wet limestone FGD systems. However, as a 

part of our evaluations, we included this option for comparison purposes. 

Similar to the caustic scrubber option, new stacks would be required along with 

flow reversal through the ESPs. As can be seen in Table 8, the capital costs are 

much higher than SDA or caustic scrubbing. Also, the footprint is much larger 

due to the need for a lime unloading and prep. This would require further study 

to determine if this technology can even be accommodated at the site. Eastman 

believes both the average and incremental cost-effectiveness are unreasonable 

and that LSFO should not be deemed BART for this application. 

 Part 2 – Energy impacts 

The cost estimates in Part 1 include any changes, positive or negative, on energy 

consumption. 

 

Part 3 – Non-air quality environmental impacts 

The cost estimates in Part 1 include any changes, positive or negative, on solid 

waste disposal and wastewater treatment. The SDA options, the dual alkali, and 

the LSFO options would all generate solid waste streams that would be disposed 

at TNO's on-site nonhazardous waste landfill. We have estimated this additional 

waste would shorten the landfill life by about 5 years (15 percent reduction in 

remaining life). 

Since the SDAs would be placed before the particulate removal devices, the 

calcium sulfate byproduct would be mixed with the flyash and any sales of 

flyash to the concrete industry would be lost. We have estimated this loss of 

flyash sales at 11,000 tons per year and that this volume would shorten the 

landfill life by an additional year or two. Loss of this volume of flyash to the 

concrete industry would mean that much more cement would be required 

Eastman BART Submittal Page 11 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 314

January 18, 2008
resulting in consumption of additional energy (natural gas) and raw materials to 

produce the cement along with the associated air emissions. It would also result 

in an increased price of concrete. 

The loss of landfill space due to either of these reasons (calcium sulfate sludge 

or loss of flyash sales) should not cause a direct environmental impact as the 

landfill has liners and leachate collection systems and should have no impact on 

groundwater. Any leachate or stormwater runoff collected in the landfill's 

stormwater basins is permitted for discharge to the South Fork Holston River. 

However, once the landfill is full, a new one will have to be sited, likely further 

from Eastman's facility. Inevitably, a new landfill will result in loss of natural 

habitat and result in other community impacts such as noise and scenic 

concerns. 

The caustic scrubber option would generate a scrubber blowdown stream 

containing dissolved salts which would require discharge to the South Fork 

Holston River (SFHR) through an NPDES permitted outfall. The salts in this 

blowdown stream would be comprised of sodium sulfate (99.5 %), sodium 

fluoride (0.4 %), and sodium chloride (0.06 %). The volume of the discharge is 

expected to be approximately 0.5 MGD. Under normal operating conditions the 

blowdown would increase Eastman's Total Dissolved Solids (TDS) loading to 

the river by approximately 238,000 lb/day. The worst-case maximum TDS 

loading could increase by as much as 351,000 lb/day. 

The SFHR immediately downstream of Eastman and the city of Kingsport is 

classified for use as an industrial water supply by the Tennessee Department of 

Environment and Conservation. Due to this classification, an ambient water 

quality criterion of 500 mg/L TDS applies in this reach of the river. 

Based on the three most recent years of quarterly data, the current average 

ambient TDS concentration downstream of Kingsport is 196 mg/L. Under 

normal scrubber blowdown discharge conditions and average river flow, the 

discharge of the scrubber blowdown would result in an increase in TDS of 

approximately 17 mg/L downstream of Kingsport. Therefore, due to the 

blowdown discharge, the average TDS concentration downstream of the 

discharge is projected to increase to 213 mg/L (196 + 17). This projected value 

is below the 500 mg/L standard and within the range of values currently 

measured in the river. 

A worst-case evaluation of the impact of the blowdown discharge was 

performed based on low flow in the river combined with the maximum upstream 

river TDS concentration, the maximum projected increase in loading (351,000 

lb/day) discharged by the scrubber, and the maximum simultaneous discharge of 

TDS from all area point sources. This worst-case analysis resulted in a 

projected downstream concentration of 349 mg/L. The discharge of scrubber 

blowdown, while increasing the level of TDS in the SFHR, would not result in 

an exceedence of the 500 mg/L water quality criterion even under worst-case 

conditions. 

 Part 4 – Remaining useful life 

 The remaining useful life is not expected to affect the BART determination. 

Eastman BART Submittal Page 12 of 34 

February 27, 2007 

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Regional Haze SIP for TN Class I Areas

Appendix L.8 - 315

January 18, 2008
3.2 Building 83 Powerhouse, Coal-fired Boiler #24 

3.2.1 Emission Unit Description 

This spreader stoker boiler is located along with six other stoker-type boilers in 

Building 83 Powerhouse at the Kingsport plant. It was built by Combustion 

Engineering and started up in 1962. It is rated at a maximum heat input capacity 

of 500 MBtu/hr. Eastern Kentucky and western Virginia type bituminous coal is 

burned in this unit along with wastewater treatment biosludge and liquid 

chemical wastes. 

This unit is used for co-production of steam and electricity in support of 

manufacturing operations at the Kingsport plant as well as the destruction of 

Biosludge from Eastman's Wastewater Treatment facility and waste chemicals. 

A high level of reliability and the ability to handle boiler load swings are 

requirements for any emissions control system. This unit is regularly used to 

control the 600 psig steam header, and at times individual boiler load can swing 

as much as 100 klb/hr in a minute or two. 

Existing Particulate Matter Controls: 

Boiler 24 is equipped with a two-field weighted wire Buell electrostatic 

precipitator built in 1971. The precipitator has 46,620 square feet of collecting 

area and a design flow of 235,000 acfm. 

Existing NOx Controls: 

Stoker boilers inherently limit NOx emissions to some degree. There is an 

overfire air system built into the stoker design. An overfire air fan delivers 

approximately 10 percent of the total air required for combustion to front wall 

air jets above and below the coal feeders and two rows of rear wall jets, one foot 

and six foot, respectively, above the grates. 

Additionally, this boiler is used routinely to burn a wastewater treatment 

biosludge that is about 85 percent water. Injection of this material cools the 

flame temperature and reduces NOx by around 20 percent much like a water 

injection system would. 

Existing SO2 Controls: Other than purchase of low to medium sulfur coal to 

meet the SIP limit of 2.4 lb/MBtu, there are no existing controls of sulfur 

dioxide emissions. The average emission rate for calendar year 2005 was 1.4 

lb/MBtu. 

Eastman BART Submittal Page 13 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 316

January 18, 2008
3.2.2 Step 1: Identify Available Retrofit Emission Control Techniques: 

Particulate matter: This boiler is equipped with a highly efficient electrostatic precipitator (ESP) for control of particulate matter emissions. The Title V 

permit requires periodic performance tests. The results of the most recent Title 

V test and the estimate of actual emissions for calendar year 2005 are shown in 

Table 9 below: 

Table 9 – Boiler 24 Particulate Emissions 

Boiler 

ID 

2005 Heat 

Input (MBtu) 

Date of 

Most 

Recent 

Test 

Particulate 

Matter 

Emissions 

(lb/MBtu) 2005 Actual Particulate Matter Emissions (tons) 

24 2,587,585 11/14/ 

2004 

0.04 

47 

Since this boiler burns some hazardous wastes, it is subject to the MACT 

standard for Boilers and Industrial Furnaces (40 CFR 63.1216). This rule sets a 

PM emission standard for existing solid fuel units of 0.03 grains per dry 

standard cubic foot (at 7% oxygen). Trial burn tests conducted pursuant to 

permitting under the hazardous waste program resulted in an emission rate of 

0.022 gr/dscf. Eastman will be conducting additional tests to assure this boiler 

will meet the MACT standard. EPA's BART guidance states that "in many 

cases, it will be unlikely that States will identify emission controls more 

stringent that the MACT standards without identifying control options that 

would costs many thousands of dollars per ton. Unless there are new 

technologies subsequent to the MACT standards which would lead to cost 

effective increases in the level of control, you may rely on the MACT standards 

for purposes of BART." (70 FR 39164). Eastman believes BART is equal to 

MACT for this boiler for the following reasons: 

1. This boiler will have to meet the applicable MACT standard. 

2. The MACT standard is very recent (October 12, 2005) and no new proven 

technologies have emerged since this recent date. 

3. It is obvious by engineering judgement that the cost to replace the existing 

ESPs or to install add-on controls such as a bag filter would be costprohibitive since actual emissions are so small. 

Nitrogen oxides 

Eastman has identified the technologies listed below in Table 10 as available 

retrofit technologies for its Boiler 24: 

Table 10 – Boiler 24 NOx Available Retrofit Technologies

Technology Description 

SOFA Separated overfire air 

SOFA/FGR Flue gas recirculation in 

conjunction with separated 

overfire air 

SNCR Selective Non-Catalytic 

Reduction (SNCR) 

SNCR/SCR Hybrid SNCR/Selective Catalytic 

Reduction 

Eastman BART Submittal Page 14 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 317

January 18, 2008
Sulfur Dioxide 

Eastman has identified the technologies listed below in Table 11 as available 

retrofit technologies for its Boiler 24: 

Table 11 – Boiler 24 SO2 Available Retrofit Technologies 

Technology Description 

FSI Furnace sorbent injection 

DSI Duct sorbent injection 

SDA/ESP Dry flue-gas desulfurization using a spray dryer 

absorber (SDA) ahead of existing ESP 

SDA/ESP-FF Conversion Dry flue-gas desulfurization using a SDA followed 

by a fabric filter 

Caustic Scrubbers Spray tower absorbers using a water/caustic 

(sodium hydroxide) solution to absorb sulfur 

dioxide 

LSFO Wet flue-gas desulfurization using limestone 

forced oxidation (LSFO) process 

3.2.3 Step 2: Eliminate Technically Infeasible Options 

Nitrogen Oxides 

Of the technologies listed in section 3.2.2 for reduction of NOx, we have 

concluded that each of them may be technically infeasible. The reasoning for 

each technology is presented below: 

FGR and SOFA: Boiler 24 is permitted to burn hazardous waste under 

the Resource Conservation and Recovery Act (RCRA), and, as such, is 

subject to the Boiler and Industrial Furnace (BIF) Maximum 

Achievable Control Technology (MACT) standard (40 CFR 63 

Subpart EEE). The boiler must meet the Destruction and Removal 

Efficiency (DRE) standard of 99.99 percent for organic compounds and 

the 100 ppmv carbon monoxide standard. Most stoker boilers operate 

with CO levels well in excess of 100 ppmv. Combustion controls such 

as FGR or SOFA designed to reduce NOx will inherently change the 

combustion conditions and result in some increase in carbon monoxide 

emissions. Even with detailed combustion system modeling, few if any 

vendors will guarantee CO levels to remain below 100 ppmv. Overfire 

air ports would likely interfere with waste burner and/or biosludge 

nozzle locations. Additionally, this boiler is used to combust Eastman's 

wastewater treatment sludge, which is biosolids containing 85-90 

percent water. Injection of this material in the flame zone has the 

effect of flame quenching and NOx reduction. This further complicates 

the NOx abatement options and increases the risk and uncertainty that 

technologies such as FGR and OFA might have a negative effect on the 

organic DRE of the boiler as well as complete combustion of the 

biosludge. Eastman can not be assured installation of this type of 

technology would not adversely affect the boiler's ability to meet these 

standards without extensive trial burn testing. 

SNCR: SNCR would require the injection of ammonia into the upper 

zone of the furnace where the temperature is in the range of 2000 deg 

F. As has been discussed, Boiler 24 serves purposes other than steam 

production. The location of the waste chemical and biosludge injection 

nozzles coincide with the location where ammonia would have to be 

Eastman BART Submittal Page 15 of 34 

February 27, 2007 

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Regional Haze SIP for TN Class I Areas

Appendix L.8 - 318

January 18, 2008
injected. It would not be possible to completely rearrange the burner 

configurations to accommodate SNCR and still be able to burn the 

waste chemicals and biosludge. The injection of ammonia so close to 

the waste chemical burners could cause formation of ammonium 

bisulfate and could also affect the DRE performance as discussed 

above. 

Hybrid SNCR/SCR: To our knowledge, SCR has yet to be installed on 

an industrial coal-fired boiler responding to steam load swings such as 

those experienced by Boiler 24. This boiler can have a steam load 

reduction of 100,000 pounds per hour over a one minute period. These 

steam load swings are accompanied by flue gas temperature changes. 

SCR is a post-combustion (“add-on”) pollution control device that 

requires ammonia injection (or urea) and a specific flue gas 

temperature range for optimum performance. In addition, because of 

the load-following nature of industrial boilers, there is the possibility of 

excess ammonia slip from the SCR, increasing overall annual operating 

costs and causing potential operational and environmental impacts. 

Any SCR system would require ammonia injection. For Boiler 24, all 

the issues related to ammonia injection discussed for SNCR apply also 

to SCR. Additionally, due to space considerations, there is no space for 

a SCR reactor. A hybrid SNCR/SCR system combines SNCR with a 

smaller in-duct catalyst section downstream of the economizer and 

upstream of the air preheater. Eastman investigated this option and 

found that there is no space between the economizer and preheater on 

Boiler 24. 

Sulfur dioxide 

Because of the high cost of high performing SO2 control technologies such as 

SDA, Eastman has investigated the technical feasibility of lower cost/lower 

performing technologies such as sorbent injection, either in the furnace or in the 

duct upstream of the ESP. 

DSI: Duct sorbent injection involves the injection of either lime or 

trona (dry sodium) in the ductwork prior to the ESP. Its success 

depends on adequate reaction time, thorough mixing, and proper 

temperature in the ductwork. Pilot work was done to develop these 

technologies in the mid-1980s, but they never gained wide commercial 

acceptance. Eastman's contacts with engineering companies that 

design DSI systems found that they would not even quote a lime-based 

system due to the following reasons: (1) higher efficiency of trona 

versus lime (i.e. much higher stoichiometric ratio of lime to achieve 

equivalent removal efficiencies using trona and (2) the necessity to 

humidify the duct with water to achieve any reasonable level of SO2 

control. While we found that a trona based system could work in 

theory, there are a number of considerations that led us to reject it as a 

practical alternative. First, the use of these systems is very limited. We 

found one facility in Colorado using a trona based DSI system. 

Second, the available suppliers of trona are very limited. In fact, we 

only learned of only one US based location for mining trona in 

Sweetwater County, Wyoming. Use of trona would be more attractive 

in a water-scarce region and located much closer to the trona supply. It 

would place Eastman's operations at inordinate risk to select a 

technology with just one supply location so far away and dependent on 

rail transportation. Third, the literature reports that trona-based DSI 

Eastman BART Submittal Page 16 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 319

January 18, 2008
has the potential to cause a brownish or orange plume due to a 

conversion of nitrogen oxide to nitrogen dioxide in the flue gas. When 

we asked the vendors of DSI technology about this phenomenon, they 

could not guarantee that under all conditions we would not experience 

the brownish plume. Given the close proximity of the residential and 

commercial development along with the applicable opacity limits, this 

would be a major factor against selection of this technology. 

FSI: Furnace sorbent injection using lime injected near the top of the 

boiler in the region of the superheater was examined. Injecting the 

reagent in the higher temperature zone (as opposed to the ductwork 

downstream of the air preheater) provides for higher reaction rates with 

SO2. However, Eastman has two major concerns with this technology. 

First, the proper reaction zone is in a region where the temperature is 

greater than 1600°F, which coincides with the area where we currently 

inject liquid chemical wastes and biosludge for destruction. Trying to 

inject limestone in this region could jeopardize both those operations. 

The second concern is the impact the lime injection would have on all 

downstream components including superheater tubes, economizer, and 

air preheaters. Given that the Eastman facility is highly dependent on 

Boiler 24 not only for steam and electricity, but also for disposal of 

liquid chemical wastes and wastewater treatment sludge, we must be 

very cautious with any technology that would pose this kind of risk. 

However, to fully evaluate this technology, we did find a supplier who 

has been working to develop this technology and a small municipal 

utility who has installed their system. Eastman personnel visited this 

facility and concluded that the technology has yet to be demonstrated 

on a long term basis of continuous operation with the high reagent feed 

rates needed to maximize its efficiency. The utility we visited only ran 

this system during periods of low load (nighttime). Therefore, Eastman 

does not believe this technology is a viable option for our Boiler 24. 

SDA/ESP: Boiler 24 has shown in internal testing that it should be 

able to comply with future hazardous waste combustor MACT 

requirements described in 40 CFR 75 subpart EEE, but any additional 

ash loading from upstream SO2 removal devices could not be handled 

by the existing precipitator without modifications or replacement. This 

can be shown by looking at the Specific Collecting Area (SCA) for the 

precipitator on Boiler 24. The SCA is a ratio of the plate collecting 

area in the precipitator in ft2 to the actual gas flow through the 

precipitator in 1000's acfm. The following is an excerpt from an article 

posted on the Institute of Clean Air Companies website describing the 

electrostatic precipitator technology: 

"Precipitator size also is related to the specific collection area 

(SCA), the ratio of the surface area of the collection electrodes 

to the gas flow. Higher collection areas lead to better removal 

efficiencies. Collection areas normally are in the range of 200-

800 ft2/1000 acfm. In order to achieve collection efficiencies 

of 99.5%, specific collection areas of 350-400 ft2/1000 acfm 

are typically used." 

The collecting area of 24 precipitator is 46,872 ft2. During high loads 

approaching the maximum firing rate of the boiler, the gas volume 

flowrate is approximately 230,000 acfm. The specific collecting area is 

204 ft2/1000 acfm (46,872/230). While this number is within the 

Eastman BART Submittal Page 17 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 320

January 18, 2008
normal design range of precipitators, this precipitator was not designed 

to meet a stringent MACR standard while handling the additional inlet 

particulate loading that would accompany a limestone or trona injection 

system whether in-duct or from a SDA. 

3.2.4 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

Eastman determined control effectiveness of the available technologies through 

a series of interactions with equipment and technology suppliers. The 

conclusions are shown in Table 12 below: 

Table 12 – Boiler 24 

SO2 Available Retrofit Technologies – Control Effectiveness

Technology Description Performance 

SDA/FF Dry flue-gas desulfurization using a 

SDA followed by a fabric filter 

Should achieve the NSPS standard of 0.2 

lb/MBtu or 92% reduction, burning low 

sulfur coal. 

Caustic Scrubbers Spray tower absorbers using a 

water/caustic (sodium hydroxide) 

solution to absorb sulfur dioxide 

Caustic scrubbers should achieve the 

NSPS standard of 0.2 lb/MBtu or 92% 

reduction, burning low sulfur coal with 

capability of achieving 95% reduction 

with medium and high sulfur coals. 

LSFO Wet flue-gas desulfurization using 

limestone forced oxidation (LSFO) 

process 

LSFO should achieve the NSPS standard 

of 0.2 lb/MBtu or 92% reduction, 

burning low sulfur coal with capability 

of achieving 95% reduction with 

medium and high sulfur coals. 

 

3.2.5 Step 4: Evaluate Impacts and Document the Results 

Part 1 Impacts Analysis (Costs) 

Eastman has prepared budgetary cost estimates (accuracy of plus 50% or minus 

25%) for the above technologies based on vendor estimates and professional 

estimators experienced in projecting total project costs for projects completed at 

the TNO facility. Eastman notes these types of cost estimates prepared before 

even preliminary engineering is completed warrant relatively high contingency 

factors. As cost estimates are refined, these contingency factors decrease, but, it 

is our experience that the final cost estimates increase along with the increased 

engineering detail. Eastman notes that, while these capital cost estimates are in 

2006 dollars, construction costs for industrial projects of this nature involving 

heavy use of steel, stainless steel, and boilermaker labor are escalating at 

unprecedented rates and actual construction costs are expected to be 

significantly higher by the time these projects would be implemented. 

For each technology, Eastman has estimated the duration of an extended outage 

that would be required to tie-in each technology. Some technologies can be 

installed during a normal annual maintenance outage. Others require several 

more weeks to complete. For these, Eastman has estimated it would incur 

$88,000 increased operating costs per week to allow for purchase of additional 

power from the grid and to idle a standby natural gas boiler. The capital cost 

estimate details are shown in Attachment 1. 

Eastman BART Submittal Page 18 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 321

January 18, 2008
Projected annual operating and maintenance costs are shown in Attachment 2. 

The unit costs assumed are shown in Attachment 3. Current raw material price 

quotations have been obtained and standard incremental costs (again, specific to 

the TNO facility) for utilities such as power, steam, inert gas, river water, etc 

have been used. Reagent costs are important factors in the overall cost analysis. 

For these, Eastman's Procurement personnel have performed market research to 

arrive at our best forecast for lime, limestone, and caustic. Annual maintenance 

costs are assumed at three percent of capital. 

These costs estimates have been made based on defined design parameters for 

each technology. The key design parameters are shown in Attachment 4. 

Eastman has used a capital recovery factor based on equipment life of 15 years 

and an interest rate of 8.5 percent. This interest rate is representative of the cost 

of capital for chemical manufacturers. 

Sulfur Dioxide 

Based on our findings from the investigation of options for the B-253 boilers, 

we can eliminate LSFO as a candidate as its capital costs are much higher for 

the same performance level as caustic scrubbing. Summary data for the 

remaining available technologies that are technically feasible (SDA/FF and 

caustic scrubbing) is provided below in Table 13: 

Eastman BART Submittal Page 19 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 322

January 18, 2008
Table 13 – Boiler 24 

SO2 Control Cost Effectiveness

Technology Capital 

Cost 

$M 

Annual O/M 

Cost 

$M 

Assumed 

Control 

Efficiency 

Annual 

SO2 

Reduced 

(tons) 

CostEffectiveness 

($/ton) 

SDA/FF $40.4 M $1.92 M 92% 1695 $3,993 

Caustic 

Scrubber 

$31.9 M $1.51 M 95% 1755 $3,042 

EPA very recently (February 27, 2006) updated the New Source Performance 

Standard (NSPS) for sulfur dioxide emissions from coal-fired industrial boilers. 

This standard is found at 40 CFR 60.42b(k) and is stated as either 0.2 lb/MBtu 

or 92 percent reduction. Given that this NSPS is so new, Eastman believes it 

represents the best level of control these sources could possibly install as BART. 

As stated in the February 27, 2006 Federal Register, this standard recognizes the 

technical difficulties of facilities firing inherently low sulfur fuels such as the 

Eastern bituminous coals Eastman utilizes from Eastern Kentucky and 

Southwest Virginia coal mines. 

Our evaluation of the technologies available that would meet the NSPS standard 

concluded that an SDA followed by a fabric filter or a caustic scrubber would be 

the most cost-effective. However, as shown above, the cost-effectiveness is too 

high ($3,993 and $3,042, respectively) to be justified. Several factors contribute 

to this conclusion. First, Boiler 24 is the only boiler in the Building 83 

Powerhouse that is BART-eligible. Therefore, there is no economy of scale 

with the lime handling system or caustic storage system as we would have at B253 (five boilers). Second, there is little available space adjacent to Boiler 24. 

The absorber for either technology would have to be either elevated above the 

adjacent rail yard or located some distance away with ductwork spanning 

railroad tracks or a roadway. There is no space to accommodate a new fabric 

filter, so we would have to either retrofit the ESP to a fabric filter, or completely 

demolish the existing ESP and build a baghouse in its place. This will be very 

costly and will require an extended shutdown of six weeks for the ESP to 

baghouse conversion or much longer for a complete replacement. Access for 

delivery and unloading of lime is very limited. Third, the cost-effectiveness of 

potential reductions is limited due to the low to medium sulfur content of 

Eastman's coal supply and the size of this boiler. FGD technologies are much 

more cost-effective for the high sulfur coal in the Midwest and on larger utilitytype boilers. 

Based on this evaluation, Eastman concludes there is no technically feasible 

alternative that is reasonably cost effective for control of sulfur dioxide from 

Boiler 24. Also, as will be discussed, the visibility improvements (see Section 

4) that could be gained from Boiler 24 using these technologies do not warrant 

this expense. 

 Part 2 – Energy impacts 

The cost estimates in Part 1 include any changes, positive or negative, on energy 

consumption. 

 

Part 3 – Non-air quality environmental impacts 

The cost estimates in Part 1 include any changes, positive or negative, on solid 

waste disposal and wastewater treatment. The SDA option would generate a 

solid waste stream that would be disposed at TNO's on-site nonhazardous waste 

landfill. We have estimated this additional waste would shorten the landfill life 

Eastman BART Submittal Page 20 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 323

January 18, 2008
by about one year. The loss of landfill space should not cause a direct 

environmental impact as the landfill has liners and leachate collection systems 

and should have no impact on groundwater. Any leachate or stormwater runoff 

collected in the landfill's stormwater basins is permitted for discharge to the 

South Fork Holston River. However, once the landfill is full, a new one will 

have to be sited, likely further from Eastman's facility. Inevitably, a new landfill 

will result in loss of natural habitat and result in other community impacts such 

as noise and scenic concerns. 

The caustic scrubber option would generate a scrubber blowdown stream 

containing dissolved salts which would require discharge to the South Fork 

Holston River (SFHR) through an NPDES permitted outfall. The salts in this 

blowdown stream would be comprised of sodium sulfate (99.5 %), sodium 

fluoride (0.4 %), and sodium chloride (0.06 %). The volume of the discharge is 

expected to be approximately 0.08 MGD. Under normal operating conditions 

the blowdown from Boiler 24 would increase Eastman's Total Dissolved Solids 

(TDS) loading to the river by approximately 36,500 lb/day. The worst-case 

maximum TDS loading could increase by as much as 53,800 lb/day. 

The SFHR immediately downstream of Eastman and the city of Kingsport is 

classified for use as an industrial water supply by the Tennessee Department of 

Environment and Conservation. Due to this classification, an ambient water 

quality criterion of 500 mg/L TDS applies in this reach of the river. 

Based on the three most recent years of quarterly data, the current average 

ambient TDS concentration downstream of Kingsport is 196 mg/L. Under 

normal scrubber blowdown discharge conditions and average river flow, the 

discharge of the Boiler 24 scrubber blowdown would result in an increase in 

TDS of approximately 3 mg/L downstream of Kingsport. Therefore, due to the 

blowdown discharge, the average TDS concentration downstream of the 

discharge is projected to increase to 199 mg/L (196 + 3). This projected value is 

below the 500 mg/L standard and within the range of values currently measured 

in the river. 

A worst-case evaluation of the impact of the blowdown discharge was 

performed based on low flow in the river combined with the maximum upstream 

river TDS concentration, the maximum projected increase in the TDS loading 

(53,800 lb/day) discharged by the scrubber, and the maximum simultaneous 

discharge of TDS from all area point sources. This worst-case analysis resulted 

in a projected downstream concentration of 282 mg/L. The discharge of 

scrubber blowdown, while increasing the level of TDS in the SFHR, would not 

result in an exceedance of the 500 mg/L water quality criterion even under 

worst-case conditions. 

 Part 4 – Remaining useful life 

 The remaining useful life is not expected to affect the BART determination. 

Eastman BART Submittal Page 21 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 324

January 18, 2008
3.2 Building 6C Cracking Furnaces #27 and #28 

These two furnaces are used to fire natural gas to provide heat to drive a cracking reaction of 

acetic acid that occurs inside the tube assemblies of the furnaces. The Title V Operating 

Permit is Permit Number 547973 which is assigned Emission Source Reference Number 

ESRN 82-0003 MSOP-16. The furnaces are designated PES B-6C-1. The furnaces also burn 

a fuel gas which is off-gas from the manufacturing process. This is the feature that makes 

these furnaces BART-eligible. Otherwise, in accordance with EPA guidance, they would be 

classified as small boilers that are not integral to the process and considered not BARTeligible. 

The furnaces were built in 1977 by Heat Research Corporation equipped with John Zink 

burners. Heat Research Corporation has now gone out of business. The furnaces are bottom 

fired box-type gas furnaces each rated for a heat duty of 18 MBtu per hour. There are six 

"burner boxes" located down each side of the furnace. Each box contains two natural gas 

burners and four fuel gas burners. Tubes are located on either side of the two rows of burner 

boxes. 

Given the low NOx emission potential from these small furnaces (10.5 tons per year each), 

post-combustion technologies such as SNCR or SCR would not be cost-effective. Of the 

combustion control technologies, the only one that could be cost-effective would be 

replacement of the 24 natural gas burners with low-NOx burners (LNB). However, since 

about 65% of the fuel on a flow basis and 45% on a heat input basis is derived from the fuel 

gas, LNB effectiveness would be very limited. Additionally, changes to the natural gas flame 

profile would have unknown effects on two important purposes of the furnaces: (1) to 

provide the correct process heat profile to provide for the cracking reaction taking place 

within the tubes in close proximity to the burner boxes and (2) to provide for 98% reduction 

of the total organic carbon (TOC) in the fuel gas. These furnaces serve as NSPS control 

devices under 40 CFR 60 Subpart NNN (New Source Performance Standards) and, as such, 

must meet a 98% control standard. For these reasons, Eastman concludes there are no NOx 

control technologies that are both technically feasible and reasonably cost-effective to reduce 

visibility in Class I Areas for these furnaces under the BART rule. 

Eastman BART Submittal Page 22 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 325

January 18, 2008
3.3 OC-Batch 

OC-Batch is a compilation of specialty organic chemical batch manufacturing equipment 

located in five different buildings at TNO. The Title V Operating Permit for this source is 

Permit Number 548412 which is assigned Emission Source Reference Number 82-0003 

MSOP-25. OC-Batch is assigned Air Contaminant Source Number ESRN 82-1011-12. Of 

the five buildings within OC-Batch, only three commenced operation during the BART time 

frame. These are B-267 (ESRN 82-1003-15), B-267A (ESRN 82-1004-05), and B-267D 

(ESRN 82-1003-01). These three buildings will be referred to hereafter as the "B-267". The 

table below excerpted from the permit further describes the source: 

Table 14 

MSOP 25 

PES OC-BATCH 

Permit Condition E3-1 SPM-1/ MPM-2, Item 10 

Process Emission Source Description Table 

Emission Unit PES 

Number 

ESR 

Number 

Number of 

Stacks 

Control / Recovery 

Devices 

Miscellaneous Batch Production Equipment B-13 82-1010-65 26 Nine Wet Scrubbers 

& Ten Condensers 

Miscellaneous Batch Production Equipment B-246 82-1004-04 18 Eight Wet Scrubbers 

Batch Production Equipment, Dryers, Mix Tank and 

Autoclaves, Solvent Stripping B-267 82-1003-15 16 Ten Wet Scrubbers & Twenty-nine Condensers 

Eight Wet Scrubbers, Two 

Dust Collectors & Nineteen 

Condensers 

Batch Production Equipment, Dryers, Solvent 

Stripping B-267A 82-1004-05 10 

Batch Production Equipment, Mix Tank and 

Autoclave, Solvent Stripping**** B-267D 82-1003-01 2 One Condenser & One Wet Scrubber 

B-267 is permitted to emit three visibility impairing pollutants (other than VOCs and 

ammonia). These are nitrogen oxides (NOx), sulfur dioxide (SO2), and particulate matter 

(PM). Each of these is controlled by either fabric filters, water scrubbers, or caustic 

scrubbers. The NOx emissions are limited to 14 tons per year (see Permit Condition E3-4). 

Ammonia emissions are limited to 22.4 tons per year (see Permit Condition E3-6). The SO2 

and PM emissions are limited from specific vents by Permit Conditions E3-8 and E3-9 (see 

table below excerpted from permit): 

Eastman BART Submittal Page 23 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 326

January 18, 2008
Table 15 

MSOP 25; PES OC-BATCH 

Permit Conditions E3-8 SPM-1/ MPM-2 and E3-9 SPM-1/ MPM-2, Item 10 

Particulate Matter (PM) and Sulfur Dioxide (SO2) Emission Limits Table 

ID Emission Unit 

PES Attachment and 

Vent I.D. 

PM 

in 

pounds 

per 

hour 

PM 

in tons 

during 

time 

T* 

SO2 

in 

pounds 

per hour 

SO2 

in tons 

during 

time 

T* 

a Cyclic Intermediates & Dye Cakes Equipment B-13, Vent L 0.10 0.41 NA NA 

b Cyclic Intermediates & Dye Cakes Equipment B-13, Vent M 0.09 0.41 NA NA 

c Cyclic Intermediates & Dye Cakes Equipment B-13, Vent P 0.02 0.09 NA NA 

d Cyclic Intermediates & Dye Cakes Equipment B-13, Vent Q neg** 0.02 NA NA 

e Cyclic Intermediates & Dye Cakes Equipment B-13, Vent N neg** neg** NA NA 

f Cyclic Intermediates & Dye Cakes Equipment B-13, Vent F 0.01 0.04 neg** neg** 

g Cyclic Intermediates & Dye Cakes Equipment B-13, Vents A-E, G, H, 

J, K, O, S-W, Y, Z 0.01 neg** NA NA 

h Miscellaneous Batch Production Equipment B-13, Vents R, I NA NA 0.05 0.11 

i Miscellaneous Batch Production Equipment B-246, Vents A-G, I, J 0.05 0.20 NA NA 

j Miscellaneous Batch Production Equipment B-246, Vents H, M-S 0.05 0.20 NA NA 

k Cyclic Intermediates Production B-246, Vent K NA NA NA NA 

l Batch Production Equipment B-267, Vents A-G, I 0.06 0.28 2.0 1.57 

m Dryers B-267, Vents K, L 0.06 0.26 NA NA 

n Mix Tank and Autoclaves B-267, Vents M-Q 

B-267D, Vents B, C **** 

NA NA NA NA 

o Solvent Stripping B-267, Vent R NA NA NA NA 

p Batch Production Equipment B-267A, Vents A-G, I 0.05 0.20 2.0 2.74 

q Dryers B-267A, Vent K 0.10 0.44 NA NA 

r Batch Production Equipment B-267A, Vent L 0.01 0.04 2.0 2.74 

s Solvent Stripping B-267A, Vent H NA NA NA NA 

TOTAL 0.61 2.59 6.05 7.16 

The control efficiencies of the air pollution control equipment currently employed are shown 

in the permit application under the tab "OC-Batch General Info". SO2 is controlled by 

caustic scrubbers estimated to achieve 98 percent control. PM is controlled to a minimum 

efficiency of 95 percent. NOx has not been emitted by B-267 in several years. However, if 

products were to be manufactured that emitted NOx, they would be controlled by caustic 

scrubbers and the annual emissions would be limited to 14 tons. Ammonia emissions are 

controlled by water scrubbers which achieve control efficiencies from 20-60 percent and are 

limited to annual emissions of 22.4 tons. Clearly, given these high efficiencies and the low 

total annual emissions allowed, further control of these pollutants would not be reasonable. 

Eastman BART Submittal Page 24 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 327

January 18, 2008
4.0 Visibility Impacts Analysis (Step 5) 

Following our Modeling Protocol (see Attachment 5), Eastman has used the Calpuff model to 

determine the degree of visibility improvement from each candidate control option for Boilers 24 – 29. 

Table 16 shows the scenarios that were modeled and Table 17 shows the results. We used three 

different metrics to measure the visibility improvement. The first is a count of the number of days per 

year that the sources cause a change in the deciview at the worst case receptor at each Class I area of 

more than 0.5 or 1.0 deciview. The second is the change in deciview caused by the sources at the 

worst case receptor in each Class I area for the eighth highest (or 98th percentile) day in the year. The 

third is the summation of the change in deciview caused by the sources at the worst case receptor for 

each Class I area for each day in the year. We then summed this third metric over each year for each 

Class I area and then took an average. This we term the "average delta deciview - year". 

The initial Calpost results were determined using the original IMPROVE equation. The values shown 

in Table 17 under the columns labeled "Daily Sum – delta deciview-yr" correspond to Calpost results 

using that version of the IMPROVE equation. Subsequent to these runs, VISTAS provided an Excel 

spreadsheet developed by VISTAS consultant Ivar Tombach which allows Calpost results to be 

adjusted for the "revised" IMPROVE equation. Eastman used this spreadsheet to generate "Revised 

IMPROVE" results. The values in Table 19 under the columns labeled "Days < 0.5/1.0 dv" and "Daily 

8th High – delta dv" are based on the revised IMPROVE equation. Since the spreadsheet provided by 

VISTAS provides results for only the 22 worst visibility impact days, in some cases it was not possible 

to determine the number of days the predicted impact was less than 0.5 dv. In these cases, to be 

conservative, the number of days above 0.5 dv predicted by the initial round of Calpost results were 

used. 

The Calpuff and Calpost input and output files for each of the scenarios modeled are available for 

review on the enclosed compact disc. 

Eastman BART Submittal Page 25 of 34 

February 27, 2007 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 328

January 18, 2008
Table 16 Calpuff Scenarios 

Modeled Emission Rates

Description 

253 SO2 

g/sec 

24 SO2 

g/sec 

253 Nonozone 

Nox 

g/sec 

253 

Ozone 

Nox 

g/sec 

24 Nox 

g/sec 

To

SO

g/s

Baseline Boilers 24-29 766 77 247 135 29 Scenario 1 SDA/ESP at B-253 222 77 247 135 29 Scenario 2 SDA/FF at B-253 61 77 247 135 29 Scenario 3 Wet FGD at B-253 38 77 247 135 29 Scenario 4 Wet FGD at B-253 + Wet FGD at Blr 24 38 4 247 135 29 Scenario 5 Scenario 3 + LNB Year-round at B-253 38 77 158 135 29 Scenario 6 Scenario 5 + SOFA at B-253 38 77 127 108 29 Scenario 7 Scenario 6 + SNCR at B-253 38 77 70 58 29 Baseline Blr 24 Only 0 77 0 0 29 Baseline B-6C + OCBatch 0.00 0.00 0.00 0.00 0.00 0

Note: The Modeling Protocol (see Attachment 1) shows the maximum daily emissions assumed for the baseline conditions. Only SO2 those are the only visibility-impairing pollutants that are considered for emission reductions from BART for TNO's BART-eligible sour

Eastman BART Submittal Page 26 of 34 

February 27, 2007 

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Table 17 – Visibility Impacts Analysis 

Baseline (Boilers 24-29) 

2001 2002 2

Daily Daily Daily Daily D

# days Sum 8th High # days Sum 8th High # days S

>0.5/1.0 

dv 

delta dvyr delta dv >0.5/1.0 dv delta dv- yr delta dv >0.5/1.0 dv d

d

Linville Gorge, NC 80/38 114.2 1.66 56/19 100.1 2.06 80/41 1GreatSmoky Mtns, TN 72/47 125.4 2.28 54/27 98.0 2.30 49/37 9Shining Rock, NC 52/30 78.3 1.44 33/9 52.6 1.22 34/14 5Joyce Kilmer, NC 34/14 56.8 1.34 21/10 45.3 1.26 29/15 4Cohutta, GA 16/6 36.2 0.90 16/4 27.5 0.81 16/8 2James River Face, VA 17/1 40.3 0.64 9/1 31.8 0.53 20/5 4

Total 451.2 355.2 3

Avg 401.5 

GRSM Avg 2.38 

Scenario 1 (253 SDA/ESP) 

2001 2002 2

Daily Daily Daily Daily D

# days Sum 8th High # days Sum 8th High # days S

>0.5/1.0 

dv 

delta dvyr delta dv >0.5/1.0 dv delta dv- yr delta dv >0.5/1.0 dv d

d

Linville Gorge, NC 38/3 58.5 0.89 29/8 52.2 1.03 46/9 6GreatSmoky Mtns, TN 50/21 66.9 1.42 34/17 53.9 1.14 36/15 5Shining Rock, NC 20/4 36.0 0.65 10/3 26.2 0.58 12/0 2Joyce Kilmer, NC 10/4 27.2 0.65 8/2 21.1 0.50 10/4 2Cohutta, GA 7/0 16.7 0.39 4/0 11.9 0.32 6/0 1James River Face, VA 2/0 19.7 0.32 1/0 16.0 0.29 4/1 2

Total 225.0 181.3 1

Avg 201.1 

GRSM Avg 1.31 

Eastman BART Submittal Page 27 of 34 

February 27, 2007 

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Table 17 – Visibility Impacts Analysis 

Scenario 2 (253 SDA/FF) 

2001 2002 2

Daily Daily Daily Daily D

# days Sum 8th High # days Sum 8th High # days S

>0.5/1.0 

dv 

delta dvyr delta dv >0.5/1.0 dv delta dv- yr delta dv >0.5/1.0 dv d

d

Linville Gorge, NC 8/0 41.4 0.70 12/4 37.3 0.74 19/4 4GreatSmoky Mtns, TN 31/7 47.8 0.99 21/6 38.6 0.94 17/6 3Shining Rock, NC 9/1 23.3 0.54 5/1 18.0 0.39 2/0 1Joyce Kilmer, NC 7/1 18.1 0.47 3/0 13.1 0.35 6/0 1Cohutta, GA 6/0 11.0 0.29 1/0 7.0 0.18 1/0 6James River Face, VA 1/0 13.4 0.21 1/0 11.7 0.25 2/1 1

Total 155.0 125.6 1

Avg 138.4 

GRSM Avg 0.95 

Scenario 3 (253 Wet FGD) 

2001 2002 2

Daily Daily Daily Daily D

# days Sum 8th High # days Sum 8th High # days S

>0.5/1.0 

dv 

delta dvyr delta dv >0.5/1.0 dv delta dv- yr delta dv >0.5/1.0 dv d

d

Linville Gorge, NC 11/0 39.0 0.60 11/4 35.1 0.72 18/4 4GreatSmoky Mtns, TN 28/6 45.1 0.97 23/6 36.3 0.91 21/6 Shining Rock, NC 9/1 21.5 0.53 5/1 16.8 0.37 1/0 1Joyce Kilmer, NC 6/0 16.7 0.45 3/0 12.0 0.31 5/0 1Cohutta, GA 5/0 10.1 0.28 1/0 6.3 0.16 1/0 6James River Face, VA 1/0 12.5 0.20 0/0 11.0 0.24 2/1 1

Total 144.9 117.5 1

Avg 128.7 

GRSM Avg 0.92 

Eastman BART Submittal Page 28 of 34 

February 27, 2007 

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Table 17 – Visibility Impacts Analysis 

Scenario 4 (Scenario 3 + Boiler 24 Wet FGD) 

2001 2002 2

Daily Daily Daily Daily D

# days Sum 8th High # days Sum 8th High # days S

>0.5/1.0 

dv 

delta dvyr delta dv >0.5/1.0 dv delta dv- yr delta dv >0.5/1.0 dv d

d

Linville Gorge, NC 8/0 31.0 0.53 9/3 24.5 0.64 14/3 3GreatSmoky Mtns, TN 19/5 37.3 0.87 16/3 30.1 0.84 13/5 2Shining Rock, NC 3/0 15.6 0.45 4/1 13.0 0.34 0/0 1Joyce Kilmer, NC 5/0 12.6 0.37 3/0 8.6 0.23 2/0 9Cohutta, GA 1/0 7.4 0.23 1/0 4.1 0.11 0/0 3James River Face, VA 1/0 9.6 0.16 0/0 8.9 0.22 1/0 1

Total 113.4 89.2 9

Avg 100.1 

GRSM Avg 0.85 

Scenario 5 (Scenario 3 + LNB Year-round at B-253) 

2001 2002 2

Daily Daily Daily Daily D

# days Sum 8th High # days Sum 8th High # days S

>0.5/1.0 

dv 

delta dvyr delta dv >0.5/1.0 dv delta dv- yr delta dv >0.5/1.0 dv d

d

Linville Gorge, NC 8/0 33.6 0.54 8/1 29.3 0.54 13/1 3GreatSmoky Mtns, TN 20/5 38.8 0.75 15/2 30.5 0.74 12/3 2Shining Rock, NC 4/0 19.0 0.38 3/1 14.2 0.31 0/0 1Joyce Kilmer, NC 6/0 14.4 0.36 2/0 10.6 0.28 4/0 1Cohutta, GA 1/0 8.7 0.23 0/0 5.7 0.16 0/0 5James River Face, VA 1/0 10.7 0.18 0/0 9.0 0.19 1/0 1

Total 125.1 99.2 1

Avg 111.3 

GRSM Avg 0.76 

Eastman BART Submittal Page 29 of 34 

February 27, 2007 

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Table 17 – Visibility Impacts Analysis 

Scenario 6 (Scenario 5 + SOFA at B-253) 

2001 2002 2

Daily Daily Daily Daily D

# days Sum 8th High # days Sum 8th High # days S

>0.5/1.0 

dv 

delta dvyr delta dv >0.5/1.0 dv delta dv- yr delta dv >0.5/1.0 dv d

d

Linville Gorge, NC 6/0 31.1 0.50 7/0 27.0 0.49 10/0 3GreatSmoky Mtns, TN 17/2 35.7 0.67 14/2 27.9 0.65 11/3 2Shining Rock, NC 4/0 17.8 0.34 3/1 13.1 0.30 0/0 1Joyce Kilmer, NC 4/0 13.41 0.32 2/0 9.94 0.25 4/0 1Cohutta, GA 1/0 8.1 0.21 0/0 5.4 0.15 0/0 James River Face, VA 0/0 9.8 0.16 0/0 8.2 0.17 1/0 1

Total 115.9 81.6 1

Avg 99.3 

GRSM Avg 0.68 

Scenario 7 (Scenario 6 + SNCR at B-253) 

2001 2002 2

Daily Daily Daily Daily D

# days Sum 8th High # days Sum 8th High # days S

>0.5/1.0 

dv 

delta dvyr delta dv >0.5/1.0 dv delta dv- yr delta dv >0.5/1.0 dv d

d

Linville Gorge, NC 3/0 26.5 0.40 5/0 22.9 0.41 6/0 2GreatSmoky Mtns, TN 10/0 29.9 0.59 8/0 23.2 0.53 9/1 2Shining Rock, NC 3/0 15.6 0.28 2/1 11.2 0.25 0/0 1Joyce Kilmer, NC 2/0 11.6 0.26 0/0 7.8 0.22 2/0 Cohutta, GA 0/0 7.1 0.18 0/0 4.9 0.14 0/0 4James River Face, VA 0/0 8.4 0.13 0/0 6.9 0.13 1/0 1

Total 99.2 76.8 8

Avg 87.3 

GRSM Avg 0.56 

Eastman BART Submittal Page 30 of 34 

February 27, 2007 

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Table 17 – Visibility Impacts Analysis 

Baseline (Boiler 24 Only) 

2001 2002 2

Daily Daily Daily Daily D

# days Sum 8th High # days Sum 8th High # days S

>0.5/1.0 

dv 

delta dvyr delta dv >0.5/1.0 dv delta dv- yr delta dv >0.5/1.0 dv d

d

Linville Gorge, NC 0/0 12.5 0.17 0/0 10.8 0.21 1/0 1GreatSmoky Mtns, TN 0/0 13.1 0.23 0/0 10.1 0.23 0/0 Shining Rock, NC 0/0 8.1 0.15 1/0 5.4 0.12 0/0 Joyce Kilmer, NC 0/0 5.8 0.15 0/0 4.4 0.13 0/0 Cohutta, GA 0/0 3.7 0.09 0/0 2.7 0.07 0/0 James River Face, VA 0/0 4.2 0.07 0/0 3.4 0.05 0/0 

Total 47.3 36.8 3

Avg 40.9 

GRSM Avg 0.23 

Baseline (B-6C Furnaces and OC-Batch) 

2001 2002 2

Daily Daily Daily Daily D

# days Sum 8th High # days Sum 8th High # days S

>0.5/1.0 

dv 

delta dvyr delta dv >0.5/1.0 dv delta dv- yr delta dv >0.5/1.0 dv d

d

Linville Gorge, NC 0/0 0.2 0.00 0/0 0.1 0.00 0/0 GreatSmoky Mtns, TN 0/0 0.2 0.01 0/0 0.2 0.01 0/0 Shining Rock, NC 0/0 0.1 0.00 0/0 0.1 0.00 0/0 Joyce Kilmer, NC 0/0 0.1 0.00 0/0 0.1 0.00 0/0 Cohutta, GA 0/0 0.0 0.00 0/0 0.0 0.00 0/0 James River Face, VA 0/0 0.0 0.00 0/0 0.0 0.00 0/0 

Total 0.6 0.6 

Avg 0.6 

GRSM Avg 0.01 

Eastman BART Submittal Page 31 of 34 

February 27, 2007 

Pre-Hearing DraftRegional Haze SIP for TN Class I Areas
Eastman BART Submittal Page 32 of 34 

February 27, 2007 

5.0 Proposed BART Determinations 

Small Sources 

As discussed above, Eastman concludes no controls are justified under BART for the B-6C Furnaces or 

OC-Batch. This conclusion is further supported by the Calpuff model run which shows the visibility 

impairment caused by these sources is 0.01 deciviews for the 98th percentile daily maximum impact at 

Great Smoky Mountains National Park. 

B-253 

 Sulfur dioxide controls:

Eastman concludes there are two technologies for control of SO2 emissions from B-253 that are 

technically feasible and reasonably cost-effective in terms of visibility improvement in Class I 

Areas. These are (1) spray dryer absorbers with fabric filters and (2) sodium hydroxide (caustic) 

scrubbers. Either of these technologies should be capable of achieving the applicable NSPS 

standards. NSPS Subpart Db was recently updated in 2006 and represents a level of control that 

should be evaluated as BART. The reasoning to support our conclusions is described below: 

As shown in the tables in Section 4, Eastman has used the Calpuff model to estimate visibility 

improvements provided by different control scenarios. The modeled baseline emissions from 

Boilers 24-29 resulted in an average visibility impairment of 401 dv-yr during the years 2000-

2002 at the six Class I Areas within 300 km of Eastman's Tennessee Operations (this value is the 

sum of deciview changes at the worst-case receptor in each Class I Area on each day in the three 

year period). The baseline case also shows an average 8th highest visibility change of 2.38 dv at 

the Great Smoky Mountains National Park (GSNP). Given that EPA defines causation of 

visibility impairment of a given source as equal to or greater than 1.0 dv, Eastman determined that 

consideration of SO2 emission reduction from its B-253 Powerhouse is warranted. As discussed 

in Section 3, we evaluated four basic technologies. These four offer three levels of control 

efficiency on the highest emission day (e.g. when sulfur content in the coal supply is high and 

boiler loads are also high). These are 71 percent provided by SDA/ESP (Scenario 1), 92 percent 

provided by SDA/FF (Scenario 2), and 95 percent offered by caustic scrubbing or LSFO (Scenario 

3). Using the average dv-yr visibility improvement as the metric to compare alternatives, Eastman 

calculates the cost-effectiveness in annualized cost per dv-yr for these alternatives as shown in 

Table 18: 

Table 18 

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) 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 335

January 18, 2008
Eastman BART Submittal Page 33 of 34 

February 27, 2007 

Based on the above results and considering the non-air quality impacts, Eastman concludes: 

• LSFO's high average and incremental cost-effectiveness values eliminate it as a 

reasonable alternative. 

• The relatively low incremental cost-effectiveness value for SDA/FF as compared to its 

average cost-effectiveness would indicate it would be a reasonable alternative and 

provide significant gains in visibility improvement as compared to SDA/ESP. 

• The superior cost-effectiveness values for caustic scrubbing would indicate it is also a 

reasonable alternative. 

• Either SDA/FF or Caustic Scrubbers would result in a predicted average 8th daily 

maximum (at the worst receptor in Great Smoky Mountains National Park when Boilers 

24 – 29 are emitting at their worst daily emission rate) of less than 1.0 dv (0.92 dv). 

Thus, by EPA's definition, they would no longer be "causing" visibility impairment. 

NOx Controls:

As discussed in Section 3, there are NOx control options available to allow the B-253 boilers to 

meet the presumptive levels specified in EPA's BART Guidance that apply to 200 MW utility 

boilers. However, the B-253 boilers are much smaller than 200 MW, so the presumptive levels do 

not strictly apply. While the available technologies (running low-Nox burners year-round and 

application of Separated Over-fire Air (SOFA), might be considered cost-effective on a dollars/ton 

basis, Eastman concludes there are other factors that, when weighed against the visibility benefits, 

do not justify the application of these technologies as BART. The risk to boiler reliability is 

discussed above in Section 3.1.5. The non-air quality impacts are discussed in Section 3, Part 3. 

These include loss of flyash sales to the concrete industry offsetting cement manufacturing, 

increased landfill rates, and loss of boiler efficiency due to higher amounts of unburned carbon in 

the flyash. Additionally, as shown in the tables in Section 4 and summarized below in Table 19, 

the incremental visibility improvements provided by these technologies are small changes relative 

to the starting baseline. 

Table 19 

Cost-effectiveness Comparisons, B-253 Nox Options 

Scenario Annualized 

Cost 

Average Dv-yr Change in 

Average 

Dv-yr 

Average CostEffectiveness 

$/dv-yr 

Incremental 

CostEffectiveness 

$/dv-yr 

Baseline N/A 401 

Baseline after 

Scenario 3 

N/A 129 

Scenario 5 

(LNB YearRound) 

$330,000 111 18 $18,334 -- 

Scenario 6 

(LNB + SOFA) 

$600,000 - 

$2,699,000 

99 30 $20,000 - 

$89,967 

$22,499 - 

$197,415 

Scenario 7 

(LNB + SOFA 

+ SNCR) 

$6,383,000 - 

$9,250,000 

87 42 $151,976 - 

$220,238 

$481,917 - 

$545,917 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 336

January 18, 2008
Eastman BART Submittal Page 34 of 34 

February 27, 2007 

Boiler 24 

Eastman concludes no control of NOx or SO2 should be required under BART for Boiler 24. This 

conclusion is supported by the following observations: 

1. The 98th percentile maximum daily deciview change attributed to this boiler at any Class I area is 

only 0.23 deciviews (dv), well below the EPA's stated definition of "contribution" to visibility 

impairment (i.e. 0.5 dv). 

2. As discussed in Section 3, Eastman could find no NOx control technology we considered 

technically feasible. The main reason for the this conclusion is the use of the boiler to not only 

burn coal to generate steam, but to also burn liquid waste chemicals and wastewater treatment 

biosludge. 

3. The most cost-effective option for control of SO2 that is technically feasible has a costeffectiveness of about $3,000-$4,000 per ton. Application of this control would result in an 

improvement in average delta-deciview-year (as defined in Section 4) of only 28.6 dv-yrs and a 

maximum improvement in the 98the percentile daily maximum visibility at a Class I area of only 

0.07 dv. 

4. Given the large required investment and substantial visibility improvement predicted by the SO2 

controls Eastman concludes are justified under BART for B-253, the substantial additional costs 

required to control Boiler 24 are not justified given the relatively small visibility improvements 

that are predicted. 

6.0 Proposed Permit Conditions and Compliance Schedule

Once EPA approves Tennessee's Regional Haze State Implementation Plan (SIP), Eastman 

proposes that its Title V permit (MSOP-02) be revised to establish an enforceable emission limit 

to reflect the BART requirements. In section 5.0, Eastman has concluded that the BART 

requirements applicable to its TNO facility would be to require Boilers 25-29 in PES B-253-1 to 

install controls (either spray dryer absorbers or caustic scrubbers as described above) to achieve 

the New Source Performance Standard (40 CFR 60 Subpart Db) for control of sulfur dioxide from 

a coal-fired boiler (see 40 CFR 60.42b(k)). In accordance with the BART Guidance (70 Federal 

Register 39172), Eastman requests this standard be applied as an average across the five boilers. 

Compliance would be demonstrated on a 30 day rolling average basis utilizing Continuous 

Emissions Monitoring Systems (CEMS) compliant with 40 CFR Part 60 or Part 75. 

Due to the complexity of the project which includes five boilers with five separate control devices, 

Eastman requests the full five year compliance period provided by the BART regulations. Each 

boiler will require an extended shutdown to tie-in the new/modified air pollution control 

equipment. These shutdowns will have to be carefully scheduled so as to not jeopardize the steam 

reserve required to reliably serve the TNO manufacturing facility. 

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Appendix L.8 - 337

January 18, 2008
Attachment 1 

Capital Cost Estimates 

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Appendix L.8 - 338

January 18, 2008
Conceptual Capital Cost Estimate

Project: BOILER 24 SNCR/SCR ESTIMATE

Date: Tuesday, April 25, 2006 Site: Kingsport

Equation Used:

ISBL = (Purchased Equip Cost + Delivery)*(Capital Factor)*(1.00 + Equip. Installation factor)*

(1.00 - (%Contingency + %General Plant))

NOTE: Values in RED require user-specified data (use TAB key and fill in appropriate cells

Purchased Equipment Cost $ 1,750,000

Eastman Provided Equipment $ -

Equipment Installation Factor 0.15 263,000

Capital Factor:

Equipment 52.78% $ 2,013,000

Electrical, DCS, & Instrumentation 5.24% 200,000

Sitework/Dismantlement 0.87% 33,333

Concrete 1.84% 70,000

Structural Steel 2.65% 101,000

Building Equipment, Fixtures, etc 0.26% 10,000

Piping and Duct Work 14.07% 536,667

Field Indirects 6.55% $ 250,000

Project Management/Engineering 15.73% $ 600,000

Total $ 3,814,000

 

Inflation rate: 

Yearly inflation 0.0%

Years for project construction 1

Total 0.0% -

Contingency 24.0% 1,186,000

 -

Conceptual Capital Estimate (Plus 50%;Minus 25%) = $ 5,000,000

Cost of Extended Shutdown $266,678

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Appendix L.8 - 339

January 18, 2008
Conceptual Capital Cost Estimate

Project: BOILER 24 SNCR ESTIMATE

Date: Tuesday, April 25, 2006 Site: Kingsport

Equation Used:

ISBL = (Purchased Equip Cost + Delivery)*(Capital Factor)*(1.00 + Equip. Installation factor)*

(1.00 - (%Contingency + %General Plant))

NOTE: Values in RED require user-specified data (use TAB key and fill in appropriate cells

Vendor Purchased Equipment Cost $ 548,000

Eastman Provided Equipment $ -

Equipment Installation Factor 0.00 -

Capital Factor:

Equipment 56.26% $ 548,000

Electrical, DCS, & Instrumentation 6.57% 64,000

Sitework/Dismantlement 2.05% 20,000

Concrete 2.26% 22,000

Structural Steel 3.01% 29,333

Building Equipment, Fixtures, etc 0.51% 5,000

Piping and Duct Work 7.97% 77,667

Field Indirects 5.34% $ 52,000

Project Management/Engineering 16.02% $ 156,000

Total $ 974,000

 

Inflation rate: 

Yearly inflation 0.0%

Years for project construction 1

Total 0.0% -

Contingency 25.0% 326,000

 -

Conceptual Capital Estimate (Plus 50%;Minus 25%) = $ 1,300,000

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Appendix L.8 - 340

January 18, 2008
Conceptual Capital Cost Estimate

Project: BOILER 24 SDA WITH FABRIC FILTER ESTIMATE

Date: Thursday, January 04, 2007 Site: Kingsport

Vendor Purchased Equipment Cost $ 5,973,700

Eastman Supplied Equipment $ -

Equipment Installation Factor 0.16 956,000

Capital Factor:

Equipment 24.10% $ 6,929,700 1.000

Electrical, DCS, & Instrumentation 7.71% 2,218,000 0.050

Sitework/Dismantlement 8.29% 2,384,000 0.015

Concrete 9.64% 2,772,000 0.035

Structural Steel 12.68% 3,645,000 0.050

Building Equipment, Fixtures, etc 4.34% 1,248,000 0.005

Piping 10.97% 3,153,150 0.300

Field Indirects 5.57% $ 1,600,000 0.04 0.065

Project Management/Engineering 16.70% $ 4,800,000 0.12 1.001

Total $ 28,750,000 2.521

 

Inflation rate: 

Yearly inflation 0.0%

Years for project construction 0

Total 0.0% -

Contingency 28.0% 11,250,000

 -

Conceptual Capital Estimate (Plus 50%;Minus 25%) = $ 40,000,000 In 2006 US Dollars

Cost of Extended Shutdown $355,571

Total Initial Costs $ 40,355,571

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Appendix L.8 - 341

January 18, 2008
Attachment 2 

Annual Operating and Maintenance Costs 

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Appendix L.8 - 342

January 18, 2008
Technology

Additional 

Operators

Added 

Electric 

Load

Added 

Electrical 

Power Cost

Reagent & 

Water Cost Maint. Cost

Ash Sale 

Lost

Additional 

Ash 

Disposal

Additional

WWT 

Cost

LOI 

Change LOI Cost

$/yr hp $/yr $/yr $/yr % $/yr $/yr % $/yr 

B-253 Nox OptionsLow-Nox Mode Year 'Round $0 0 $0 $0 $0 100 $120,540 $0 25 $209,475 SOFA (non-boosted) $0 0 $0 $0 $114,000 25 $30,135 $0 0 $0 SOFA (boosted) $0 875 $226,910 $0 $480,000 25 $30,135 $0 5 $41,895 SOFA (non-boosted)+SNCR $0 315 $81,687 $4,981,538 $240,000 100 $120,540 $0 0 $0 SOFA (boosted) + SNCR $0 900 $233,393 $5,329,602 $645,000 100 $120,540 $0 5 $41,895 SCR $0 1,250 $324,157 $7,089,506 $2,850,000 100 $120,540 $0 0 $0 Natural Gas Reburn $0 0 $0 $27,687,322 $441,825 0 $0 $0 0 $0 B-253 SO2 OptionsDry FGD with ESP $300,000 2,692 $698,197 $2,251,336 $2,550,000 100 $283,895 $0 0 $0 Dry FGD + FF Retrofit $300,000 5,050 $1,309,593 $2,192,564 $3,750,000 100 $359,613 $0 0 $0 LSFO $300,000 5,047 $1,308,863 $999,022 $4,800,000 0 $317,856 $2,848 0 $0 Caustic Scrubber $300,000 2,610 $676,839 $4,840,113 $2,280,000 0 $0 $45,202 0 $0 Dual Alkali $300,000 2,825 $732,594 $2,504,936 $3,060,000 0 $317,856 $219,816 0 $0 Boiler 24 SO2 OptionsSDA + FF $0 525 $136,146 $563,579 $1,200,000 0 $16,797 $0 0 $0 Caustic Scrubber $0 285 $73,908 $653,142 $780,000 0 $0 $1,808 0 $0 

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Attachment 3 

Unit Cost 

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Appendix L.8 - 344

January 18, 2008
Attachment 3

Unit Costs

Units Costs Used in Comparison of NOx and SO2 Reduction Technologies

Variable Cost Units

Electric power cost 0.04 $/kwh

Natural gas cost 8 $/MMBTU

Coal cost 2 $/MMBTU

Ash sale price 5 $/ton

Landfill + hauling cost 5.5 $/ton

Demineralized water cost 1.39 $/kgal

City water cost 1.38 $/kgal

Filtered water cost 0.11 $/kgal

Plant air cost 0.14 $/kscf

Instrument air cost 0.17 $/kscf

50% urea cost 0.4 $/lb 9.59 lb/gal

19.4% ammonia cost 0.0825 $/lb 7.33 lb/gal

Limestone cost 28 $/ton

Lime cost 120 $/ton

Caustic 150 $/ton

Trona cost 140 $/ton

Operators 75,000 $/yr

Cost of 1% Change in Loss on Ignition (B-253) 8,379 $/percent LOI Increase

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Appendix L.8 - 345

January 18, 2008
Attachment 4 

Design Parameters 

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Appendix L.8 - 346

January 18, 2008
Attachment 4

Design Parameters

Reagent Stoichiometric Ratio Gas Volume (acfm)

Flue Gas 

Temperature (deg 

F)

Pressure 

Drop (inches 

water)

Ammonia Slip 

(ppm)

Catalyst life 

(years)

Boilers 25-29

SNCR urea 1.40 286,000 2000 N/A 5 N/A

Selective Catalytic Reduction ammonia >1.0 286,000 740 @ MCR 8 2-3 3

Caustic Scrubber caustic 1.23 286,000 315 3.5 N/A N/A

Dual Alkali Scrubber caustic and lime 1.23 286,000 315 3.5 N/A N/A

Dry FGD lime 1.20 286,000 315 5.3 N/A N/A

Dry FGD + FF Retrofit lime 1.20 286,000 315 11.3 N/A N/A

Wet LSFO limestone 1.08 286,000 315 7.3 N/A N/A

Boiler 24

Caustic Scrubber (FRP) caustic 1.23 235,000 325 3.5 N/A N/A

Dry FGD + New Fabric Filter lime 1.20 235,000 325 11.3 N/A N/A

Average Sulfur Content (lb/Mbtu) 1.6

Maximum Sulfur Content (lb/Mbtu) 2.4

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Appendix L.8 - 347

January 18, 2008
Attachment 5 

Modeling Protocol

 (Included in Attachment L.6) 

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Appendix L.8 - 348

January 18, 2008
BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS 

TVA CUMBERLAND FOSSIL PLANT 

July 17, 2007

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Appendix L.8 - 349

January 18, 2008
CONTENTS

Section Page

I. Introduction.......................................................................................1 

II. BART Engineering Analysis..................................................................3 

III. BART Modeling Analysis.....................................................................6 

IV. Conclusions....................................................................................16 

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Appendix L.8 - 350

January 18, 2008
I. Introduction 

Guidelines for Best Available Retrofit Technology (BART) evaluations have been issued 

by the U. S. Environmental Protection Agency (EPA) in the Federal Register (70 FR 

39104-39172). A BART determination is required for any eligible source that “emits any 

air pollutant which may reasonably be anticipated to cause or contribute to any 

impairment of visibility” within any of the 156 mandatory Class I federal areas. A source 

is considered to cause visibility impairment if it is responsible for a 1.0 deciview (dv) 

change in visibility; it is considered to contribute to visibility impairment if it is 

responsible for a 0.5 dv change in visibility. 

 

Major stationary sources are BART-eligible if they meet three criteria: 

(1) Potential to emit at least 250 tons per year of a visibility-impairing pollutant. 

(2) “Commenced construction” as of August 7, 1977, but not in operation more 

than 15 years (August 7, 1962). 

 (3) Belong to one of the 26 listed source categories in the guidance. 

If an eligible source is concluded to be subject to BART, determination of the appropriate 

control alternative must consider the following statutory factors: 

(1) existing control equipment 

(2) cost of compliance 

(3) energy and non-air environmental impacts 

(4) remaining useful life of the source 

(5) degree of visibility improvement expected from the application of controls 

The TVA Cumberland Fossil Plant (CUF), located in Stewart County, TN, has two 

pulverized-coal-fired steam generators that are considered BART eligible. Units 1 and 2 

are nominally rated at about 1325 MW each. Both units are equipped with flue gas 

desulfurization (FGD) systems for sulfur dioxide (SO2) control, selective catalytic 

reduction systems for controlling nitrogen oxides (NOx), and electrostatic precipitators 

(ESPs) to control particulate matter (PM) emissions. In addition, CUF currently uses 

hydrated lime injection on both units to mitigate stack opacity. 

The two units at CUF are subject to the EPA Clean Air Interstate Rule (CAIR). Based on 

guidance from EPA and the Tennessee Department of Environment and Conservation 

(TDEC), compliance with CAIR satisfies BART requirements for SO2 and NOx

emissions at electric generating units. As a result, this BART analysis only considers 

PM10 emissions. 

Three Class I areas are located within 300 km of CUF: Mammoth Cave National Park 

(MACA), Mingo Wilderness Area (MING), and Sipsey Wilderness Area (SIPS). The 

locations of the CUF stacks, the three Class I areas that are within 300 km, and the 

VISTAS 12-km and 4-km grid for domain 3 are shown in Figure 1. 

1

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Appendix L.8 - 351

January 18, 2008
Figure 1. Location of CUF and Class I Areas within 300 km (MACA, MING, and 

SIPS). The red box shows the VISTAS 12-km domain, and the green box shows 

the VISTAS domain #3, the 4-km subdomain. 

As discussed in Section III, exemption modeling showed that two units at CUF are 

subject to BART requirements for PM10. Therefore, an engineering analysis was required 

to determine whether there is a technically and economically feasible control scenario 

that represents BART. The modeling analysis also demonstrated that approximately 96 

percent of the visibility impacts at the affected Class I areas can be attributed to 

condensable PM10 emissions (i.e., SO3). So the engineering evaluation for CUF focuses 

on control of SO3/H2SO4 emissions. 

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Appendix L.8 - 352

January 18, 2008
II. BART Engineering Analysis

Emissions

Based on emissions testing at TVA facilities using hydrated lime injection, stack 

emission levels of about 7 ppmdv SO3 (both corrected to 3%02) can be achieved. This 

value was used as the baseline for the engineering analysis. 

One option was identified as technically feasible for controlling additional SO3 emissions 

at CUF--a wet ESP . An ESP controls PM by imparting a negative charge to fly ash 

particles entering the device and collecting them on positively charged plates. In a wet 

ESP, the fly ash is removed by flushing the collection plates with water. Wet ESPs are 

very expensive, requiring large capital investments. They also require large volumes of 

water for cleaning the plates. This technology is capable of achieving an SO3 emission 

level of approximately 2 ppmdv. 

Based on actual fuel usage rates for CUF Units 1 and 2 in 2005, baseline annual 

emissions of SO3 (expressed as H2SO4) are about 828 tons each. A wet ESP would 

reduce emissions to about 237 tons/yr. 

Cost of Compliance

Capital equipment costs for the wet ESP were estimated from a vendor quote for another 

TVA facility (“Budgetary Proposal, Paradise Units 1 & 2, Babcock & Wilcox Company, 

July 3, 2007”). The costs were scaled using engineering assumptions and applied to CUF 

Units 1 and 2. Other capital and annual costs were based on information in the EPA Air 

Pollution Control Cost Manual, Sixth Edition. 

Capital costs are presented in Table 1, and annual costs are presented in Table 2. The 

total capital investment for a wet ESP is about $176 million per unit. Total annual costs 

are about $50.5 million per year. The corresponding cost effectiveness is over $85,000 

per ton. Based on these results, a wet ESP is clearly economically infeasible for CUF and 

should, therefore, be eliminated from consideration as a basis for BART. 

Non-air Environmental Impacts

As stated previously, a wet ESP is a water intensive system. According to the EPA Air 

Pollution Control Cost Manual, a wet ESP uses at least 5 gal/min of water per 1,000 cfm 

of flue gas. Based on this ratio, operating wet ESPs on both units at CUF would consume 

over 16 billion gallons per year of additional water and require treatment of an equivalent 

volume of wastewater. 

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Appendix L.8 - 353

January 18, 2008
Table 1. Capital Costs for Wet ESP: CUF Unit 1 or 2 

 

 Direct Costs Basis Cost 

 Purchased Equipment Costs (PEC) 

 ESP+auxiliary equipment (ESP) $69,700,000

 Instrumentation 0.10 ESP $6,970,000

 Sales taxes 0.03 ESP $2,091,000

 Freight Included -- 

 PEC $78,761,000

 

 Direct Installation Costs (DIC) 

 Foundations & supports 0.04 PEC $3,150,440

 Handling & erection 0.50 PEC $39,380,500

 Electrical 0.08 PEC $6,300,880

 Piping 0.01 PEC $787,610

 Insulation for ductwork 0.02 PEC $1,575,220

 Painting 0.02 PEC $1,575,220

 DIC $52,769,870

 

 Total Direct Costs (DC) $131,530,870

 

 Indirect Costs 

 Engineering 0.20 PEC $15,752,200

 Construction and field expenses 0.20 PEC $15,752,200

 Contractor fees 0.10 PEC $7,876,100

 Start-up 0.01 PEC $787,610

 Performance test 0.01 PEC $787,610

 Model study 0.02 PEC $1,575,220

 Contingencies 0.03 PEC $2,362,830

 Total Indirect Costs (IC) $44,893,770

 

 

Total Capital Investment 

(TCI)=DC+IC $176,424,640

 

*Wet ESP equipment costs based on vendor estimate. Other costs are based on information 

 from the EPA Air Pollution Control Cost Manual, Sixth Ed. 

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Appendix L.8 - 354

January 18, 2008
Table 2. Annual Costs for Wet ESP: CUF Unit 1 or 2 

 

Direct Annual Costs 

(DC) Bases & Assumptions 

 

Operating Labor 

 Operator $ 32,850 2 hrs/shift, 365 days/yr, $15/hr 

 Supervisor $ 4,928 15% of operator labor 

 Coordinator $ 10,950 1/3 of operator labor 

Maintenance 

 Labor $ 69,063 SCA=103 ft2/1000 cfm, 4.5 million cfm 

 Material $ 787,610 1% of PEC 

Utilities 

 Electricity-fan $ 599,342 2" H2O Δp, $0.06/kWh 

 

Electricityoperating $ 330,830 capacity factor (CF)=0.7 

 Water $ 1,655,640 5 gal/min per 1000 cfm, $0.2/1000 gal, CF=0.7 

Waste Disposal $ 16,556,400 $2/1000 gal 

Total DC $ 20,047,613 

 

Indirect Annual Costs 

(IC) 

 Overhead $ 543,241 60% of operating labor and materials 

 Administrative charge $ 3,528,493 2% of TCI 

 

Payment in lieu of 

taxes $ 1,764,246 1% of TCI 

 Insurance $ 1,002,169 1% of TCI 

 Capital recovery $ 23,619,516 CRF = 0.1339 

 Total IC $ 30,457,664 

 

Total Annual Cost $ 50,505,277 

 

*Based on information from the EPA Air Pollution Control Cost Manual, Sixth Ed. Capital recovery 

factor (CRF) based on 12% interest rate and 20-yr equipment life. 

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Appendix L.8 - 355

January 18, 2008
III. BART Modeling Analysis

TVA conducted BART modeling for CUF following both the general VISTAS protocol 

and the revised TVA BART protocol submitted to the TDEC on July 28, 2006. Modeling 

was conducted on the VISTAS 4-km domain for the state of TN (dom 3). Three Class I 

areas are located within 300 km of PAF: MACA at 153 km, MING at 233 km, and SIPS 

at 223 km. 

Emissions used for the BART modeling were taken from the workbook 

“CUF_CY05_BART_rev3.xls,” which is included in this submittal in electronic format. 

Extensive documentation on how the emissions were calculated is provided in that file. 

All CALPUFF control files, output files and ozone files are also included in electronic 

format. The stack parameters used in the modeling analysis are summarized in Table 3. 

Table 3. Stack Parameters for CUF 

CALPUFF modeling was conducted following the example files that were made 

available by Earth Tech, Inc. Following the example files, PM emissions were set to 1 

g/s for all size categories. The emission rate for SO3 was entered as H2SO4 in g/s as 

indicated on the “BART” worksheet of the emissions spreadsheet 

“CUF_CY06_BART_rev3.xls.” All emissions for the modeling analysis were calculated 

assuming operation at maximum heat input to conservatively represent maximum 24-

hour actual emissions. Emissions of HNO3 and PM-NO3 were set to zero, because no 

credible emissions factors were available for these species for EGUs. Support for setting 

HNO3 and PM-NO3 to zero was found in some SMOKE emissions factors provided by 

VISTAS. In the SMOKE emissions table provided by VISTAS, the factor provided for 

PM-NO3 was zero, as shown in Table 4. The SMOKE emissions factors were not used 

except as justification for setting emissions of HNO3 and NO3 to zero. 

Table 4. Emissions profiles from SMOKE for EGUs (provided by VISTAS). 

profile Pllt species split divisor mass_frac 

22001 PM2_5 PEC 0.0183 1 0.0183 

22001 PM2 5 PMFINE 0.852 1 0.852 

22001 PM2 5 PNO3 0 1 0 

22001 PM2 5 POA 0.0107 1 0.0107 

22001 PM2 5 PSO4 0.119 1 0.119 

Stack Parameter Unit 1 Unit 2 

Stack Height (m) 194 194 

Base Elevation (m) 118 118 

Stack Diameter (m) 11.7 11.7 

Gas Exit Velocity (m/s) 19.7 19.7 

Stack Gas Exit Temperature (oK) 321 321 

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January 18, 2008
The following steps were used for CALPUFF exemption modeling on the 4-km domain: 

1. A CALPUFF simulation was conducted for each of the three years, 2001, 2002 

and 2003 for each unit of CUF. 

2. Emission factors entered in the POSTUTIL control file are shown in Table 5. The 

emission factors were calculated in the spreadsheet 

“pm_distribution_CUF_rev3.xls” for each unit at CUF. Data from the emissions 

spreadsheet “CUF_CY05_BART_rev3.xls” were used to determine the emission 

factors following the example spreadsheet pm-distribution-sample-source which 

was provided by Earth Tech. 

3. POSTUTIL was run on each output file from step 1. 

4. The outputs from POSTUTIL were summed over the two units of CUF using the 

CALSUM utility. 

5. CALPOST was run separately for each class I area and each year using the output 

from step 4. Method 6 was used. CALPOST was run separately for each class I 

area using the output from step 5. Method 6 was used. The baseline was based 

on the annual average for each Class I area, taken from Appendix B of Guidance 

for Estimating Natural Visibility Conditions under the Regional Haze Rule, EPA 

454/B-03-005, published in September, 2003. The f(RH) values were taken from 

Table A-3, Monthly Site-Specific f(RH) Values for Each Mandatory Federal 

Class I Area, Based on the Centroid of the Area (Supplemental Information), 

found in the same EPA document.

6. The lists of delta DVs in the CALPOST.LST files for each of the 3 years were 

used to get the 98th percentile (8th highest value) for each individual year. The 

data from the 3 years were combined together and sorted by delta DV to find the 

98th percentile value (22nd highest value) for the three years combined together. 

Table 5. Emission Rates for CUF 1 and CUF 2 calculated for POSTUTIL 

CUF 1 Hydrated Lime Emission Rates (g/s) Species 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 

SOA 3.5607 3.5607 7.12 

NO3/HNO3 0.00 

CUF 2 Hydrated Lime Emission Rates (g/s) Species 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 

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January 18, 2008
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 

Exemption Modeling

Results of the CALPUFF modeling for CUF on the 4-km domain are presented in Tables 

6 and 7. A summary of CALPUFF results for the Class I areas that are located within 

300 km is presented in Table 6. More detailed information for the Class I areas that are 

within 300 km of CUF, including the date and receptor where the delta dv was at or 

above the 98th percent contribution, is provided in Table 7. The 98th percent contribution 

is used in the 4-km simulations. The 98th percentile is defined as the 8th largest value for 

each individual year or the 22nd largest value for all 3 years together, whichever is most 

conservative. 

Table 6. Summary of CALPUFF Results for CUF on 4-km Grid. 

Class I Area Dist 

(km) 

from 

source 

to 

nearest 

receptor

# Days with 98th

Percent > 0.5 dv, 

98th percentile, 

in Class I Area 

(2001) 

# Days with 98th

Percent > 0.5 dv, 

98th percentile, 

in Class I Area 

(2002) 

# Days with 98th

Percent > 0.5 dv, 

98th percentile, 

in Class I Area 

(2003) 

# Days with 98th

Percent > 0.5 dv, 

98th percentile 

in Class I Area 

for 3-Year 

Period (2001-

2003) 

Delta dv Used 8th highest 8th highest 8th highest 22nd highest 

MACA 153 46 1.133 42 1.359 32 1.015 120 1.19 

MING 233 3 0.295 3 0.322 5 0.404 11 0.344 

SIPS 223 7 0.459 10 0.539 10 0.557 27 0.539 

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January 18, 2008
Table 7. 98th-percentile Results for Affected Class I Areas 

(Delta dv Rankings #1-22 for 2001-2003) 

YEAR DAY RECEPTOR DELTA dv 

MACA 

2001 205 290 2.116 

2002 11 1 1.940 

2002 334 9 1.852 

2002 10 290 1.797 

2002 155 8 1.584 

2001 207 172 1.576 

2003 217 8 1.484 

2002 204 297 1.433 

2002 180 8 1.430 

2001 186 8 1.422 

2001 163 204 1.362 

2002 208 290 1.361 

2002 342 48 1.359 

2003 166 204 1.317 

2002 164 3 1.281 

2003 34 290 1.267 

2003 335 172 1.256 

2001 138 8 1.233 

2002 210 204 1.231 

2003 241 9 1.228 

2002 13 258 1.190 

2003 203 297 1.190 

MING 

2003 174 349 0.976 

2001 246 304 0.885 

2001 120 349 0.834 

2001 213 349 0.813 

2002 175 346 0.795 

2003 254 321 0.687 

2003 281 304 0.685 

2002 273 321 0.601 

2003 348 304 0.574 

2003 261 329 0.560 

2002 38 304 0.529 

2001 220 321 0.494 

2003 207 349 0.474 

2003 282 322 0.407 

2003 284 349 0.404 

2002 216 303 0.385 

2003 78 304 0.375 

2003 232 321 0.371 

2001 96 335 0.353 

2002 173 349 0.353 

2002 348 322 0.347 

2001 197 321 0.344 

SIPS 

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Appendix L.8 - 359

January 18, 2008
YEAR DAY RECEPTOR DELTA dv 

2002 54 457 1.122 

2001 264 438 1.101 

2001 301 493 1.094 

2003 60 493 1.080 

2002 306 493 1.045 

2003 100 493 1.008 

2003 296 439 0.990 

2002 290 457 0.937 

2001 271 493 0.876 

2001 10 439 0.746 

2001 193 457 0.734 

2003 101 440 0.714 

2003 90 443 0.698 

2002 341 457 0.693 

2003 248 439 0.690 

2003 359 439 0.644 

2002 289 496 0.626 

2002 305 439 0.598 

2003 205 457 0.557 

2002 12 457 0.552 

2002 318 457 0.539 

2003 7 439 0.539 

Because exemption modeling for CUF shows impacts greater than 0.5 dv at MACA and 

SIPS, both units at CUF are subject to BART requirements, and an engineering analysis 

and determination modeling were conducted. 

Determination Modeling

The BART determination modeling for CUF was conducted for MACA and SIPS, which 

are the two Class I areas with impacts >0.5 dv. Because Units 1 and 2 have similar 

design and operating parameters, determination modeling conducted for Unit 2 was 

considered applicable to both units. Determination modeling calculations used the same 

steps as the exemption modeling, except that step 4 (CALSUM) was omitted and 

CALPOST was run on the outputs from POSTUTIL. 

Results of the CALPUFF determination modeling for CUF on the 4-km domain are 

presented in Tables 8-11. Summaries of CALPUFF results for the baseline and wet ESP 

control levels are presented in Tables 8 and 9, respectively. More detailed information 

for these options is provided in Tables 10 and 11. 

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January 18, 2008
Table 8. Summary of CALPUFF Results per Unit for Baseline on 4-km Grid. 

Table 9. Summary of CALPUFF Results per Unit for Wet ESP on 4-km Grid. 

Class I Area Dist 

(km) 

from 

source 

to 

nearest 

receptor

# Days with 98th

Percent > 0.5 dv, 

98th percentile, 

in Class I Area 

(2001) 

# Days with 98th

Percent > 0.5 dv, 

98th percentile, 

in Class I Area 

(2002) 

# Days with 98th

Percent > 0.5 dv, 

98th percentile, 

in Class I Area 

(2003) 

# Days with 98th

Percent > 0.5 dv, 

98th percentile 

in Class I Area 

for 3-Year 

Period (2001-

2003) 

Delta dv Used 8th highest 8th highest 8th highest 22nd highest 

MACA 153 18 0.593 24 0.712 9 0.532 51 0.620 

SIPS 223 2 0.236 2 0.278 3 0.287 7 0.278 

Class I Area Dist 

(km) 

from 

source 

to 

nearest 

receptor

# Days with 98th

Percent > 0.5 dv, 

98th percentile, 

in Class I Area 

(2001) 

# Days with 98th

Percent > 0.5 dv, 

98th percentile, 

in Class I Area 

(2002) 

# Days with 98th

Percent > 0.5 dv, 

98th percentile, 

in Class I Area 

(2003) 

# Days with 98th

Percent > 0.5 dv, 

98th percentile 

in Class I Area 

for 3-Year 

Period (2001-

2003) 

Delta dv Used 8th highest 8th highest 8th highest 22nd highest 

MACA 153 0 0.201 0 0.240 0 0.178 0 0.210 

SIPS 223 0 0.079 0 0.094 0 0.095 0 0.093 

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Appendix L.8 - 361

January 18, 2008
Table 10. 98th-percentile Baseline Results per Unit for MACA and SIPS 

(Delta dv Rankings #1-22 for 2001-2003) 

YEAR DAY RECEPTOR DELTA dv 

MACA 

2001 205 290 1.130 

2002 11 1 1.031 

2002 334 9 0.986 

2002 10 290 0.955 

2002 155 8 0.833 

2001 207 172 0.830 

2003 217 8 0.781 

2002 204 297 0.753 

2001 186 8 0.752 

2002 180 8 0.752 

2002 208 290 0.716 

2001 163 204 0.713 

2002 342 48 0.712 

2003 166 204 0.691 

2002 164 3 0.673 

2003 34 290 0.666 

2003 335 172 0.651 

2001 138 8 0.644 

2002 210 204 0.644 

2003 241 9 0.642 

2002 13 258 0.624 

2003 203 297 0.620 

SIPS 

2002 54 457 0.586 

2001 264 438 0.574 

2001 301 493 0.570 

2003 60 493 0.564 

2002 306 493 0.546 

2003 100 493 0.526 

2003 296 439 0.516 

2002 290 457 0.487 

2001 271 493 0.455 

2001 10 439 0.386 

2001 193 457 0.379 

2003 101 440 0.370 

2003 90 443 0.361 

2002 341 457 0.359 

2003 248 439 0.356 

2003 359 439 0.333 

2002 289 496 0.323 

2002 305 439 0.308 

2003 205 457 0.287 

2002 12 457 0.284 

2002 318 457 0.278 

2003 7 439 0.278 

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Appendix L.8 - 362

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Table 11. 98th-percentile Wet ESP Results per Unit for MACA and SIPS 

(Delta dv Rankings #1-22 for 2001-2003) 

YEAR DAY RECEPTOR DELTA dv 

MACA 

2001 205 290 0.385 

2002 11 1 0.355 

2002 334 9 0.341 

2002 10 290 0.328 

2002 155 8 0.283 

2001 207 172 0.280 

2003 217 8 0.263 

2002 180 8 0.254 

2001 186 8 0.253 

2002 204 297 0.253 

2002 342 48 0.243 

2001 163 204 0.241 

2002 208 290 0.24 

2003 166 204 0.233 

2003 34 290 0.230 

2002 164 3 0.227 

2003 335 172 0.222 

2001 138 8 0.220 

2002 210 204 0.216 

2003 241 9 0.215 

2002 13 258 0.212 

2001 147 8 0.210 

SIPS 

2002 54 457 0.201 

2003 60 493 0.194 

2001 301 493 0.192 

2001 264 438 0.192 

2002 306 493 0.186 

2003 100 493 0.182 

2003 296 439 0.173 

2002 290 457 0.164 

2001 271 493 0.152 

2001 10 439 0.130 

2003 101 440 0.128 

2001 193 457 0.126 

2003 90 443 0.124 

2002 341 457 0.121 

2003 248 439 0.118 

2003 359 439 0.112 

2002 289 496 0.108 

2002 305 439 0.103 

2002 12 457 0.095 

2003 205 457 0.095 

2002 318 457 0.094 

2003 7 439 0.093 

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Appendix L.8 - 363

January 18, 2008
For each unit, a wet ESP is predicted to reduce the visibility impact at MACA from 0.712 

dv to 0.240 dv. The model predicts a reduction in the visibility impact at SIPS from 

0.287 dv to 0.095 dv. 

Quality Control/Quality Assurance Procedures 

The following quality control/quality assurance procedures were practiced by TVA in 

conducting BART modeling for CUF. 

A comparison was made between the switch settings for CALPUFF that were found in 

Appendix B of the IWAQM report and in the example file provided by TRC 

Environmental. Since the VISTAS BART protocol stated that settings in Appendix B of 

the IWAQM document were to be used, these settings were followed for the most part. 

Deviations were made for three reasons: (1) the change was necessary to conduct BART 

modeling; (2) the change in switch settings would not affect the simulation, or (3) the 

change was necessary because of refinements to CALPUFF since Appendix B was 

published. Examples of (1) include NSPEC and NSE, the number of species and the 

number of emitted species. The values given in Appendix B were too low for VISTAS 

BART modeling. Another example is BCKNH3, the background NH3 concentration. 

The value given in Appendix B was 10, but the VISTAS BART Protocol specified that a 

value of 0.5 should be used. An example of change type (2) is IMESG, a variable that 

determines whether status messages will be sent to the screen. Examples of change type 

(3) are SVMIN and SWMIN. Because of refinements to CALPUFF, 12 values were 

needed for each of these arrays instead of the 6 values specified in Appendix B. The 

values given in the sample file provided by TRC Environmental were used for the 

additional 6 values. 

Two modelers independently reviewed the setup files for CALPUFF, POSTUTIL, and 

CALPOST and determined what values to use when a question arose. Both modelers 

also conducted complete simulations to assure that the procedures worked properly. 

Two modelers independently converted the coordinates for TVA’s BART-eligible 

facilities and the Class I receptors from latitude/longitude to lambert conformal conic 

using the COORDS facility in CALPUFF. A third person calculated the conversion for 

the TVA BART-eligible facilities by a completely independent method that did not 

involve the use of CALPUFF. Comparison of these results ensured that the conversion 

was conducted correctly. (The values calculated independently of COORDS were not 

used in the BART modeling; they were used only as a check of the reasonableness of the 

values calculated using COORDS). Calculated distances between TVA facilities and 

Class I areas were checked against “eyeball” estimates from maps and calculations 

conducted by GIS to determine that they were reasonable. The distances were sorted in 

spreadsheets to find the distance between the TVA facility and the closest receptor at 

each Class I area. This value was used to determine whether the Class I area is within 300 

km of the TVA facility. The datum used, NWS-84 6370KM, matched the datum 

specified in the sample CALMET files provided by TRC Environmental. In addition, 

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Appendix L.8 - 364

January 18, 2008
maps of the land use, terrain, sources, receptors and ozone stations were viewed in 

CALVIEW to ensure that they looked reasonable. 

Two calculations were added to the PM-distribution spreadsheets to ensure that they were 

calculated correctly. A sum was added to the percents of filterable material to be sure 

that the percents added up to 100 (E29). A sum was added to the line containing the total 

g/s for each of the species (N29). The value in cell N2 was compared against the initial 

total g/s in cell C12 as a final check that the spreadsheet was correct. 

In the CALPOST setup files, receptors for all Class I areas located within 300 km were 

included. Subsets of these receptors were designated in the setup file so that, for each 

CALPOST simulation, only the receptors from a single Class I area were considered. 

Thus, a separate CALPOST run was conducted for each Class I area located within 300 

km of a TVA BART-eligible facility. For the 4-km run, the results for the three years 

were imported into a Microsoft® Excel spreadsheet and sorted to determine the days with 

the highest delta dv impacts. 

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Appendix L.8 - 365

January 18, 2008
IV. Conclusion

Application of a wet ESP would reduce visibility impacts at MACA, MINGO, and SIPS. 

However, the excessive costs associated with wet ESPs, as well as the large volumes of 

water required, make that option infeasible as a basis for BART. As a result, TVA 

proposes that no additional control be required under the BART regulations. 

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Appendix L.8 - 366

January 18, 2008
4APT-APB 

Mr. Barry R. Stephens, P.E. Director 

Tennessee Division of Air Pollution Control 

9th Floor, L & C Annex 

401 Church Street 

Nashville, TN 37243-1531 

Dear Mr. Stephens: 

Thank you for the opportunity to review the proposed Best Available Retrofit 

Technology (BART) technology evaluation for the Alcoa, Inc.-Tennessee Operations 

dated May 18, 2007. 

Enclosed are our comments on the Alcoa Inc. document. Enclosure 1 describes 

our comments on the control and cost analyses. Enclosure 2 details our comments on the 

modeling analysis. 

We appreciate your transmittal of this package for our consideration. If you have 

questions regarding this letter, please contact Jimmy Hou of the Region 4 staff at (404) 

562-8965. 

Sincerely, 

Kay T. Prince 

Chief 

Air Planning Branch 

Enclosures 

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Appendix L.8 - 367

January 18, 2008
Enclosure 1: Control and Cost Analyses 

1. The declaration that the use of coke at less than 3% is infeasible will require 

extensive supporting documentation, since coke suppliers can produce coke as 

low as 0.25%. 

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Appendix L.8 - 368

January 18, 2008
Enclosure 2: Modeling Analysis 

General Comments on the Modeling Documentation and for the State

1. Source emission and stack data: One of the most important factors in any modeling 

exercise is to ensure that the source parameters (e.g., emission rates, stack parameters) 

are correct. EPA Region 4 recommends that the State carefully compares these 

parameters with existing permits, databases, etc. to ensure that appropriate values are 

being used for the BART modeling. 

2. Deciview Threshold and Modeling exemption: The exemption threshold value 

selected by the State in determining whether a BART-eligible source can reasonably be 

anticipated to cause or contribute to visibility impairment must be documented in the 

State Implementation Plan (SIP), as must the basis for the States’ selection of this 

threshold. The threshold should be no higher than 0.5 delta deciview (dv) (e.g. >/= 0.5 is 

subject to BART, < 0.5 is exempt per the BART guidelines). In establishing the 

threshold, States should consider the number of emission sources affecting the Class I 

Areas at issue, the magnitude of the sources’ impacts, and the location of the sources. 

(See 70 FR 39161-39162, July 6, 2005.) The appropriateness of the threshold used by 

the State will be subject to public review and comment, and States could consult with the 

affected States or Regional Planning Organizations or Federal Land Managers in 

establishing this value. 

3. BART-Eligible Units: We suggest that the documentation for the BART SIP 

requirements include a list of all emission units at the ALCOA facility which includes 

dates of operation, existence, pollutants and potential emissions. The list or table 

containing all of the Alcoa emission units would illustrate why each emission unit was or 

was not considered BART-eligible. If BART-eligible based on dates and later determined 

otherwise, that reason should also be presented. 

Specific Modeling Comments 

1. Section 3.1, page 3-4: 

a. The submittal states that Potlines 1 and 2 and the anode bake furnace are already 

equipped with sophisticated emission control equipment for PM, so the BART 

determination for these emission units focuses primarily on potential reductions 

for SO2 and NOX. The submittal should also discuss why the “sophisticated 

emission controls” represent BART controls. The use of sophisticated controls 

does not adequately justify this assumption. 

b. The submittal also indicates that the remaining 21 units in Table 1 have 

baghouses to control PM emissions and that the baghouses represent the best 

available control for these units. Do existing permits contain conditions to ensure 

that the baghouses are properly operated and maintained? Since the emissions 

from these units are claimed to be insignificant, it important to assure that the 

emissions controls are operated properly. 

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Appendix L.8 - 369

January 18, 2008
2. CALPOST Method 8

a. Light extinction was calculated in a version of the CALPOST postprocessor that 

utilizes the new IMPROVE equation using a new method called Method 8. The 

submittal states that Method 8 provides a better correspondence between the 

measured visibility and that calculated from pollutant concentrations simulated by 

the model. This model change is not the Visibility Improvement –State and 

Tribal Association of the Southeast (VISTAS) model that has been agreed upon 

for use in the BART modeling. It has not been sufficiently and clearly 

demonstrated that the new CALPOST provides a better method to incorporate the 

new IMPROVE equation into the CALPUFF modeling system.

b. There is no documentation on how the version of CALPOST with Method 8 was 

developed. Quality assurance that was used in its development, coding and 

integration of the new equation with CALPUFF to develop visibility impacts was 

not discussed. 

c. It is incumbent upon the state and the facility to ensure that this new model is 

developed and documented in an appropriate and detailed manner, suitable for use 

in the BART modeling and review by EPA.

d. CALPOST Method 8 sets the maximum relative humidity at 98 percent by default 

but the user can change it. EPA guidance caps the relative humidity at 95 percent.

i. What relative humidity was used in the Alcoa BART modeling?

ii. Why was the relative humidity changed when the EPA guidance caps 

it at 95 percent?

iii. What f(RH) curve (i.e., December 2000 Flag report, EPA f(RH) curve 

or IWAQM 1998 f(RH). If something other than that recommended in 

the VISTAS modeling protocol was used, an explanation is required. 

e. What is the background and rationale to support the new f(RH) curves that are 

incorporated in the CALPOST Method 8 processor?

f. What level of independent review has the CALPOST Method 8 processor 

undergone in its development and implementation?

g. The new IMPROVE equation and the modified CALPOST processor is not a 

generic model that EPA Region 4 recognizes to be a part of the CALPUFF 

modeling system. Its use should be justified on a case-by-case basis. A detailed 

justification which addresses the rationale for using the new equation and the 

performance of the new equation versus the old equation should be provided. 

Attachment B provides EPA Region 4’s review of the use of a spreadsheet 

developed by the Visibility Improvement – State and Tribal Association for the 

Southeast (VISTAS) with CALPUFF that could be used if the appropriate 

documentation to support the modified CALPOST model is not available. 

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Appendix L.8 - 370

January 18, 2008
h. Nitrogen dioxide concentrations: The report does not discuss the origin of the 

NO2 data used in CALPOST. EPA Region 4 has determined that it would be 

acceptable to use the total NOx concentration as a surrogate for NO2 (i.e., 

conservatively assume that all NOx is NO2). The total NOx concentration can 

easily be obtained when running CALPOST by turning on the switch to produce 

NOx concentration output – no changes to the CALPUFF modeling are needed. 

i. Sea Salt: Documentation on how sea salt concentrations were developed and used 

with the new IMPROVE equation and the BART modeling was not, but should be 

explicitly discussed in the submittal. 

j. Referencing a method to use the new IMPROVE equation as developed through a 

paper funded by VISTAS does not provide the documentation needed to support 

the modeling. 

3. CALMET: 

The report on page 4-3 states that 1-kilometer (km) grid resolution modeling was 

used in the refined modeling of the facility. The documentation on the development 

of the 1-km meteorological data using CALMET was incomplete. The 

documentation should discuss the CALMET input options used to develop the data 

and the performance assessment and quality assurance used to review the data for 

accuracy and usefulness. Descriptions of the model are provided with options that 

could be used. However details on what were used in developing the meteorological 

data is required in the submittal. 

4. CALPUFF Results 

Table 8 on page 5-25 of the report presents the CALPUFF modeling results for two 

control scenarios. Control Scenario 2 is listed as “3.0% Sulfur Coke.” Looking at the 

modeling results presented in Tables 5-1 through 5-14 in Appendix B of the report, 

the results for Control Scenario 2 are really the modeling results for the baseline 

“Base Case Run.” Table 8 should be revised to indicate that “3.0% Sulfur Coke” is 

really the “Base Case” as it represents the current operation. 

Appendix B of the Submittal

1. Page 4-11: The first sentence on this page states that “each source is modeled by 

(the?) group of the same emission rates and their source contributions are summed at 

the end” to provide for flexibility. It is unclear what the “group of same emission 

rates” is referencing. 

2. Even though modeling supposedly produced delta visibility impacts at Mammoth 

Cave that were less than 0.5 deciviews, the modeling results should be presented. 

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Appendix L.8 - 371

January 18, 2008
3. Tables 5-1 through 5-12 should be consistent in how the modeling results are 

presented. All of the top eight delta visibility impacts should be presented for 

Linville Gorge, Shining Rock and Cohutta. 

4. The state should determine in the Regional haze SIP why the 0.5 visibility threshold 

was applicable for the BART exemption modeling. Also, the state should determine 

if a 0.5 dv threshold should be used to determine visibility improvement for the 

BART determination modeling. 

5. It is unclear what version of CALMET, CALPUFF and the other processors were 

used in the BART modeling. 

 

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Appendix L.8 - 372

January 18, 2008
Attachment A 

Excerpt from August 24, 2006 Q&A Document 

4. How should a State document in the SIP that BART controls will be installed and 

in operation as expeditiously as practicable, but no later than 5 years after 

approval of the SIP? Must BART controls be housed in a Title V permit 

modification? 

As specified in 40 CFR 51.308(e)(1)(v), States are required to ensure each source 

subject to BART install and operate BART as expeditiously as practicable, but in 

no event later than 5 years after approval of the implementation plan revision. 

States should ensure that BART requirements in a SIP are written in a way that 

clearly specifies the individual emission unit(s) subject to BART regulation and 

the time by which the emission unit(s) must begin to comply with the BART 

limit. Because the BART requirements are ‘‘applicable’’ requirements of the 

CAA, they must be included as title V permit conditions according to the 

procedures established in 40 CFR part 70 or 40 CFR part 71. Under 70.7(f)(1)(i) 

Title V permits must be reopened and revised to include new applicable 

requirements if the permit has three or more years of life. The reopening must be 

completed within 18 months after promulgation of the new applicable 

requirement and the reopening must follow the same procedures (public 

comment, etc) as apply to initial permit issuance. This may require that States 

provide commitments in the SIPs to ensure that all applicable construction 

permits under Title 1, and the operating permits under Title V are revised in time. 

The following elements, at a minimum, must be addressed to ensure the BART 

controls are adopted into the State’s SIP. These elements are discussed in detail 

with other circumstances in 40 CFR Part 51, Appendix Y – Section V. 

• Name of source facility and the specific emission units and pollutants 

being controlled. (40 CFR 51.308(e)(1)(i) & (ii)). 

• Specifics of the controls, control efficiency(ies), emissions reductions 

expected 

• Enforceable emission limitations representing BART (40 CFR 

51.308(d)(3);(e)) 

• Schedules for compliance with BART (40 CFR 51.308(d)(3);(e)) 

• A requirement that each source subject to BART maintains the control 

equipment and establish procedures to ensure such equipment is properly 

operated and maintained. (40 CFR 51.308(e)(v)) 

• Reporting, monitoring, and recordkeeping requirements adequate to 

determine the source’s compliance (40 CFR Part 51, Appendix Y – V). 

• Averaging times and reference methods to determine compliance (40 

CFR Part 51, Appendix Y – V). 

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Appendix L.8 - 373

January 18, 2008
ATTACHMENT B 

U.S. EPA Region 4 Review of the VISTAS Methodology for Implementing the 

New IMPROVE Equation with CALPUFF for BART Modeling 

The original Interagency Monitoring of Protected Visual Environments (IMPROVE) 

algorithm for estimating light extinction from particle speciation data tends to 

underestimate light extinction for the highest haze conditions and overestimate it for the 

lowest haze conditions. It uses a ratio of organic compound mass to carbon mass of 1.4, 

though the literature indicates that the ratio is higher especially in remote areas. It also 

does not include a term for sea salt, which is important at sites near the ocean coasts. As 

a result of these limitations, the IMPROVE Steering Committee commissioned the 

development of a new IMPROVE algorithm, which they adopted for use in December 

2005. It is our understanding that some sources want to use the new IMPROVE 

equation to take advantage of sea salt and site-specific Rayleigh scattering for BART 

modeling in Region 4. A new methodology is needed to process the mass concentrations 

from CALPOST using the new IMPROVE equation so that the Best Available Retrofit 

Technology (BART) analyses could consider both the old and new IMPROVE equations. 

The U.S. Environmental Protection Agency (EPA) and the Federal Land Managers 

(FLMs) from the National Park Service and the U.S. Fish and Wildlife Service have 

determined that adding site-specific data (e.g. sea salt and site-specific Rayleigh 

scattering) in the old IMPROVE equation, for a hybrid approach is not recommended. A 

methodology to post-process CALPUFF/CALPOST data to implement the entire new 

IMPROVE equation with CALPUFF is needed. The new IMPROVE equation cannot be 

directly implemented using the existing version of the CALPUFF model without 

additional post-processing or model revision. The Visibility Improvement - State and 

Tribal Association for the Southeast (VISTAS) tasked Dr. Ivar Tombach to develop such 

a methodology. The State of North Carolina submitted a request for the review of this 

methodology to EPA and the FLMs. 

The VISTAS methodology for implementing the new IMPROVE equation using existing 

CALPUFF/CALPOST output is contained in a spreadsheet developed by Dr. Ivar 

Tombach. The VISTAS procedure is essentially a modification of CALPOST, which 

provides the calculations of the light extinction from the CALPUFF output. This 

proposed VISTAS methodology constitutes a non-regulatory modeling application 

requiring compliance with section 3.2 of Appendix W, Part 51: Guideline on Air Quality 

Models. Requests for using this alternative method should be made by each individual 

State allowing time for EPA Region 4 approval prior to the public hearing on the State’s 

Regional Haze State Implementation Plan (SIP) submittal. A generic approval for all 

applications of this alternative method will not be provided. EPA approval will be 

granted on a case-by-case basis, considering the merits of the State’s request including 

supporting documentation for using the alternative methodology for the BART modeling.

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Appendix L.8 - 374

January 18, 2008
Documentation to support the use of the VISTAS methodology is needed and should 

include the following. 

 

- A rationale for why the new IMPROVE equation is needed for the application 

(e.g., the old IMPROVE algorithm does not account for the impact of sea salt on 

background conditions which can be important for coastal sites);

- An evaluation, specific to the Class I Areas being examined for the modeling 

demonstration, of the new vs. old equations performance when compared to 

measured/monitored values (e.g., as provided in "Revised IMPROVE Algorithm 

for Estimating Light Extinction from Particle Speciation Data" found on 

http://vista.cira.colostate.edu/IMPROVE/Publications/GrayLit/019_RevisedIMPR

OVEeq/RevisedIMPROVEAlgorithm3.doc ); and

- A detailed description of the procedures used in the modified-post processing 

methodology (e.g., spreadsheet or other post-processing calculations with explicit 

discussion on the limitations and assumptions in developing the data inputs).

 

Additionally, consistency should be maintained when applying the new vs. old equations 

when calculating natural background, current, and future visibility impacts at Class I 

Areas. For example, if the new IMPROVE equation is used to calculate the natural 

background visibility impact for a Class I area for the BART modeling, the new 

IMPROVE equation should also be used to calculate the BART source’s current and 

future impact on visibility. 

The VISTAS methodology contained in the spreadsheet developed by Dr. Ivar Tombach 

appropriately implements the features of the new IMPROVE equation, with the exception 

of the nitrogen dioxide term. The methodology provides an adequate procedure for 

calculating the bimodal split for sulfates, nitrates and organics. This is accomplished by 

following the procedures for calculating the large and small fractions based on a 

concentration cutpoint of 20 ug/m3 , as recommended in the technical support document 

for the new IMPROVE algorithm ("Revised IMPROVE Algorithm for Estimating Light 

Extinction from Particle Speciation Data" found on 

http://vista.cira.colostate.edu/IMPROVE/Publications/GrayLit/019_RevisedIMPROVEeq

/RevisedIMPROVEAlgorithm3.doc). The methodology also incorporates the new sizefraction specific f(RH) factors contained in the technical support document. These new 

procedures are used to calculate the visibility impacts from the source and also to adjust 

natural background values (to account for sea salt and the bimodal split of sulfates, 

nitrates and organics). The background value is appropriately added to the source 

concentration for determining the correct size fraction for sulfates, nitrates and organics. 

The calculated visibility impacts are then compared with the adjusted natural background 

visibility to determine the change in visibility impact for the comparison with the 

threshold value. 

As noted above, the methodology does not adequately address the nitrogen dioxide (NO2) 

term in the new IMPROVE equation. It indicates that the NO2 term is small and 

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Appendix L.8 - 375

January 18, 2008
insignificant. This may not be the case in each specific application. NO2 concentrations 

are not readily available from CALPUFF/CALPOST when using the default MESOPUFF 

II chemistry option. Therefore, EPA Region 4 has determined that it would be 

acceptable to use the total NOx concentration as a surrogate for NO2 (i.e., conservatively 

assume that all NOx is NO2). The total NOx concentration can easily be obtained by 

turning on the switch to produce NOx concentration output when running CALPOST– no 

changes to the CALPUFF modeling are needed. The NOx concentration is obtained in 

CALPOST using the following option in Input Group 1 of the CALPOST Input File: 

! ASPEC = NOX !. With the addition of this recommendation for addressing the NO2 

term, we believe the VISTAS methodology to incorporate the new IMPROVE equation is 

acceptable on a case-by-case basis and upon consultation with the EPA Regional Office. 

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Appendix L.8 - 376

January 18, 2008
U.S. EPA Region 4 Comments on the 

BART Exemption Modeling and 

BART Determination for 

E.I. DuPont de Numours & Company 

Old Hickory Plant 

Old Hickory, Tennessee 

November 30, 2007 

BART Exemption Modeling Report: Final Report – Results of BART Modeling & 

Engineering Analysis @ Maximum 24-hour Firing Rates Using the New IMPROVE 

Equation, dated September18, 2007. 

1. Section 1, Summary, Page 4: 

The report indicates that the emissions from the DuPont Old Hickory Plant do not 

cause or contribute to visibility impairment at any of the nearby Class I areas 

based on the results of modeling done using the new IMPROVE equation. EPA 

disagrees with this conclusion. We agree that the new IMPROVE equation may 

be used for evaluating visibility impacts. However, DuPont’s analysis did not use 

the entire equation (see comment #2 below). Therefore, we do not agree that the 

modeling results can be used to support DuPont’s claim of not contributing to 

visibility impairment at the Mammoth Cave Class I area. 

2. Section 4, Modeling Results with the New IMPROVE Equation, Page 7: 

The modeling results presented in Table 4-1 show that the modeled 98th percentile 

values for all of the cases are less than or equal to 0.5 dV. We believe that the 

values presented in Table 4-1 are not correct because the calculations using the 

new IMPROVE equation did not include the nitrogen dioxide (NO2) term. The 

details of the calculations are contained in a MS Excel spreadsheet included on 

the compact discs in Appendix 3 of the report. The calculations of the NO2 term 

are missing from the spreadsheet. No explanation is given for omission of the 

NO2 term. We believe that the NO2 term should be included whenever the new 

IMPROVE equation is used. Also, the levels of NOx emissions from the DuPont 

facility are too large to ignore the NO2 term. 

To evaluate the impact of not including the NO2 term in the new IMPROVE 

equation, we conducted some hypothetical calculations using the PSD NOx Class 

I area increment (2.5 ug/m3 = 1.3 ppb) and the PSD NOx Class I area 

insignificance level (0.1 ug/m3 = 0.052 ppb). We believe that these are 

reasonable levels to evaluate based on the potential NOx emissions rates from the 

facility (1056 tons/yr from boiler 20 and 786 tons/yr from boiler 24). Assuming 

either of these values for NOx concentration at the Class I area results in the 

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eighth-high delta-dV impact for Mammoth Cave @ 24-hr maximum emission 

rates in 2003 exceeding 0.5 dV when the NO2 term is included. 

We agree with the Tennessee Department of Environment and Conservation’s 

(TDEC) recommendation that the 24-hr maximum emission rates should be used 

for the modeling. This recommendation is contained in EPA’s BART guidance 

and the VISTAS BART Modeling Protocol. Therefore, we believe that the 

modeling results presented in the report can not be used to meet the exemption 

modeling criteria. (See comment #1 below for further discussion of this issue.) 

3. Section 4, Modeling Results with the New IMPROVE Equation, Page 7:

Based on DuPont’s failure to include the NO2 term in the new IMPROVE 

calculations, we believe that DuPont has not met the exemption modeling criteria. 

Therefore, the BART determination and evaluation of potential controls analysis 

contained in the companion report has been reviewed to evaluate potential BART 

controls for the facility. Our comments on the BART determination are presented 

below. 

BART Exemption Modeling Report: Final Report – Results of BART Modeling & 

Engineering Analysis @ Maximum 24-hour Firing Rates Using the Old IMPROVE 

Equation, dated September18, 2007. 

1. Section 2.1, Revised Modeling Basis for the Current Assessment, Pages 11-

12: 

DuPont presents arguments that using the 24-hr maximum emission rates is not 

appropriate for the modeling because the boilers do not operate at these emission 

rates during the summer. DuPont’s arguments are reasonable, but we believe that 

it is not appropriate to use an annual average emission rate for the modeling. A 

potential option would be to develop a 24-hr maximum emission rate that occurs 

during the summer months which could be used in place of the year-round 24-hr 

maximum value when modeling the emissions during the summer months. The 

year-round 24-hr maximum value should still be used for the non-summer 

months. This would require an additional set of CALPUFF runs be performed. 

2. Section 3, Data Analysis of Control Options Modeling and Cost Analysis, 

Page 18: 

Generally, we agree with DuPont’s proposal to use the cost thresholds developed 

in the Clean Air Interstate Rule (CAIR) which are $1700/ton for NOx and 

$1800/ton for SO2. However, we do not think that these should be considered 

absolute limits, but are good “ball-park” estimates. Any controls that have costs 

close to these thresholds should be considered for BART. 

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3. Section 3, Data Analysis of Control Options Modeling and Cost Analysis, 

Page 17-18: 

Based on the data presented in Tables 3-4 and 3-5, the option to use “1.5% Sulfur 

Coal with No Scrubbing” appears to potentially be a cost-effective control option. 

Also, the use of Low- NOx Burners on Boiler 20 Only or both Boilers 20&24 

appears to also be potentially cost effective. Therefore, we recommend that 

TDEC carefully consider these as possible BART controls for the facility. 

On Page 18, DuPont states that NOx reductions from potential controls do not 

result in significant visibility improvements. We agree that the visibility 

improvements from the NOx controls are much less than those predicted for the 

SO2 controls. The data in Tables 3-4 and 3-5 indicate significant visibility 

improvements from the “1.5% Sulfur Coal with No Scrubbing” and the other 

potential SO2 control options. Therefore, it is more important to carefully 

consider controls of SO2 than controls on NOx when making the BART 

determination. 

4. Section 4, Conclusions, Page 21: 

The Class I area being impacted is Mammoth Cave National Park located in 

Kentucky. A decision on significance of impacts should be made in consultation 

with the Kentucky Department for Environmental Protection (KY DEP) and the 

National Park Service (NPS). It is important to consider the decisions KY DEP is 

making for other sources impacting Mammoth Cave. This consultation process 

should also be documented in the SIP. 

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January 18, 2008
4APT-APB 

Mr. Barry R. Stephens, P.E. Director 

Tennessee Division of Air Pollution Control 

9th Floor, L & C Annex 

401 Church Street 

Nashville, TN 37243-1531 

Dear Mr. Stephens: 

Thank you for the opportunity to review the proposed Best Available Retrofit 

Technology (BART) technology evaluation for the Eastman Chemical CompanyTennessee Operations dated April 18, 2007. 

Enclosed are our comments on the Eastman Chemical Company document. 

Enclosure 1 describes our comments on the control and cost analyses. Enclosure 2 

details our comments on the modeling analysis. 

We appreciate your transmittal of this package for our consideration. If you have 

questions regarding this letter, please contact Jimmy Hou of the Region 4 staff at (404) 

562-8965. 

Sincerely, 

Kay T. Prince 

Chief 

Air Planning Branch 

Enclosures 

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Enclosure 1: Control and Cost Analyses 

1. Section 3.1.2, page 4

a. Bullet 3 under section 3.1.2 states that “it is obvious by engineering judgment that 

the cost to replace an electrostatic precipitator is cost-prohibitive. The discussion 

to support this position was not presented in this section of the submittal, but 

should be provided or referenced in this section. 

b. Emissions from a 2005 stack test and estimates from 2005 actual emissions are 

presented in Table 2-B. These rates are proposed to be much lower than the 0.07 

lb/MMBtu MACT rate requirement. The 24-hr maximum rates as determined 

over the last five years and used in the BART modeling should also be presented 

in the comparison to the MACT rate. 

2. Table 1, page 2: Sulfur content is listed as a control for the B-252-2A-E, B-83-2C, B6C-1A and B-6C01B emission units. The table should also describe how the sulfur 

content is used as a control (e.g., permit condition, etc.) 

3. Sources of potential controls: Possible technologies that could be considered for 

BART compliance were presented in Tables 2, 3, and 4 for B-253. The submittal did 

not identify the sources or databases or procedures used (e.g., information sources) to 

determine the controls that are discussed. 

4. Cost Analysis: Section 3.2.5 of the submittal indicates that a capital recovery factor 

based on equipment life of 15 years was used. This assumption needs to be supported 

for the scrubbers as they typically have a 20 year life, or it should be changed to use a 

20 year life. 

5. Pollution Prevention (P2) and Process Changes: When identifying all available 

retrofit control technologies, the “Guidelines for BART Determinations under the 

Regional Haze Rule” (BART Guidelines) clarify that consideration should be given 

not only to add-on controls but also improvement in the performance of existing 

controls and P2. The analysis does not discuss the facility’s evaluation of options for 

P2 and process changes for the BART-eligible units, with the exception of staged air 

combustion. 

6. Proposed BART Controls: Table 19 in Section 5 of the submittal indicates that 

application of low-NOx burners (LNB) year-round appears to be a cost effective 

option. However, Eastman indicates that other factors, including the non-air quality 

impacts and visibility benefits, do not justify use of LNB year-round as BART for 

NOx control. It is recommended that Tennessee closely evaluates this decision not to 

apply LNB year-round. Tennessee may wish to request additional justification from 

Eastman to support their contention that year-round LNB should not be BART for 

NOx control on the B-253 boilers. 

7. Proposed BART Controls: Sections 5 and 6 of the submittal indicate that Eastman is 

proposing to meet the BART requirements by installing either spray dryer absorbers 

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with fabric filters or caustic scrubbers on Boilers 25-29 to achieve the New Source 

Performance Standard (40 CFR Part 60, Subpart Db) for control of sulfur dioxide. 

Section 6 contains a brief description of the proposed permit conditions and 

compliance schedule. EPA’s August 2006 Q&A Document includes suggestions for 

incorporating BART controls into Title V permits and information which should be 

included in the Regional Haze SIP submittal (Attachment A to these comments 

provides the Q&A that addresses this issue). We recommend that the suggestions in 

the attached Q&A be followed for developing the SIP. 

8. Proposed BART Controls: In Section 6 of the submittal, Eastman proposes to revise 

the Title V permit to establish an enforceable emission limit reflecting the BART 

requirements. It further suggests that a 30 day rolling average (using a CEMS) of the 

average emissions of their five boilers be used to demonstrate compliance. This is 

acceptable, but the enforceability will need to be reassessed once this is submitted as 

an enforceable permit condition; for instance, they must contain some recordkeeping 

requirements. Also, in order to approve their proposal to average the five units 

together for compliance, Eastman must demonstrate that the emission reductions from 

each pollutant being controlled for BART would be equal to those reductions that 

would be obtained by simply controlling each of the BART-eligible units. 

9. Summary BART Determination Table: There could be a summary table in the report 

when it is revised or in the Regional Haze state implementation plan (SIP) 

documentation when either the report or SIP is submitted to address EPA concerns. 

A summary table that presents the different control scenarios modeled, cost 

information, modeled baseline and improvement, modeled emission rates, amount of 

reductions achieved by pollutants and whether or not BART controls was feasible. 

An example table that could be used to summarize the BART assessment for controls 

could include the following. 

Control Is existing 

control 

MACT? 

Cost of 

compliance 

Energy impacts? Non-air 

quality 

impacts? 

Remaining 

useful life 

Visibility 

change (dv)

BART 

feasible? 

Reduction 

potential 

(tpy) 

Emission rates 

modeled 

SO2

NOx 

PM 

SO2 units 

NOx units 

PM units 

SO2

NOx 

PM 

SO2 units 

NOx units 

PM units 

SO2

NOx 

PM 

SO2 units 

NOx units 

PM units 

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Enclosure 2: Modeling Analysis 

1. Visibility Improvement as indicated by modeling: A 0.5 deciview threshold is cited 

throughout the determination submittal and is used as the measurement of visibility 

improvement for an assessed potential control. Although this level has been used as a 

threshold of visibility impairment for the BART exemption modeling and has been 

recommended for use in modeling large electrical generating units and power plants, 

no such threshold for the BART determination of visibility improvement has been 

recommended. The BART guidelines indicate that the State should assess the 

visibility improvement in conjunction with the other factors for determining BART 

for the source. A level greater or less than 0.5 deciviews may be appropriate 

depending on the evaluation of the other factors. 

2. Modeling Protocol:

a. The submittal indicates that a modeling protocol is included in Attachment 5. 

The protocol was not submitted and is needed for a complete review. 

b. The note at the end of Table 16 on page 26 of the Determination narrative 

states that the modeling protocol is included in Attachment 1. However, 

Attachment 1 contains the capital cost estimates. 

3. Modeling Documentation: 

a. Written documentation for the modeling demonstration was not, but should 

be, submitted. The following are some comments about the modeling 

documentation that should be addressed. 

b. Written documentation, in addition to the input and output files that were 

provided on the CD, explaining how the modeling protocol was actually 

implemented and used to develop the BART determination and/or exemption 

modeling should be included in the determination submittal. Much of this 

documentation goes beyond the switches that are set in running the models 

and processors in the CALPUFF modeling system. Also, any changes from 

the proposed procedures presented in a modeling protocol should be clearly 

explained. 

c. Emission Rates: 

i. It is unclear how emission rates for the modeling were developed and 

whether or not they represented the maximum 24-hour rates over the 

assessment years. 

ii. One of the most important factors in any modeling exercise is to 

ensure that the source parameters (e.g., emission rates, stack 

parameters) are correct. This type of information was not, but should 

be, documented in the submittal. EPA Region 4 recommends that the 

State carefully compares the model input parameters with existing 

permits, databases, etc. to ensure that appropriate values are being 

used for the BART modeling. 

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4. New IMPROVE Equation: 

a. The determination submittal indicates that the new IMPROVE algorithm was 

used for the BART modeling. The documentation does not include the 

spreadsheet used to post-process the CALPOST results for using the new 

equation. This VISTAS approach is not a generic approach that EPA Region 4 

recognizes to be a part of the CALPUFF modeling system. Its use should be 

justified on a case-by-case basis. A detailed justification which addresses the 

rationale for using the new equation and the performance of the new equation 

versus the old equation should be provided. Attachment B provides EPA 

Region 4’s review of the use of the VISTAS spreadsheet with CALPUFF. 

b. Nitrogen dioxide concentrations: Documentation on the use of the new 

IMPROVE equation in the modeling was not provided. The report does not 

discuss the origin of the NO2 data, the year or years used to develop this data 

and why those years were used. EPA Region 4 has determined that it would 

be acceptable to use the total NOx concentration as a surrogate for NO2 (i.e., 

conservatively assume that all NOx is NO2). The total NOx concentration can 

easily be obtained when running CALPOST by turning on the switch to 

produce NOx concentration output – no changes to the CALPUFF modeling 

are needed. 

c. Sea Salt: Documentation on how sea salt concentrations were developed and 

used with the new IMPROVE equation and the BART modeling was not, but 

should be discussed in the submittal. 

5. Table 17: 

a. State determines/recommends criteria for modeled visibility improvement: 

We appreciate Eastman TNO providing several alternative approaches to 

determine the visibility improvement for the suite of controls used in the 

BART determination. It should be noted that visibility improvement based on 

the performance of a criterion at the worst case receptor does not necessarily 

support or indicate visibility improvement for a modeled control. It is one 

way of examining this statutory BART assessment factor but it may be that 

improvement occurs very little at the worst case receptor but large 

changes/improvement may have occurred over a large number and days in the 

receptor network modeled. 

b. Even though it is up to the State to determine the visibility improvement 

criteria, we recommend that the change in delta deciview between the baseline 

and different scenarios should be reported as a part of the documentation. 

c. The number of days per year the sources caused a change in visibility greater 

than 0.5 and 1.0 deciviews at the worst case receptor was one criterion used to 

show visibility improvement for a control. Based on this criterion, all control 

scenarios indicate significant visibility improvement. 

d. It is unclear what an average deciview per year metric that is developed from 

all Class I areas impacted by the Eastman TNO facility really means with 

respect to visibility improvement. It would seem that improvement could be 

better at one or more Class I areas. If that is the case and then improvement at 

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January 18, 2008
each areas should be reviewed on its on merits and weighed by the state using 

their visibility improvement criteria. 

e. A typo exists in this table under scenario 2 for Linville Gorge under the 2003 

daily 8th high. The delta dv is listed as “,87”. 

6. BART Eligibility Assessment for Eastman TNO sources: We recommend that the 

documentation for the BART SIP requirements include a list of all emission units at 

each facility, dates of operation, visibility impairing pollutants and potential 

emissions. The list or table should illustrate why each emission unit was or was not 

considered BART-eligible. If the unit was considered BART-eligible based on dates 

of operation and later determined otherwise, that reason should also be presented (i.e., 

if the source was determined to be exempt through the exemption modeling step). 

Additional suggestions for documentation that should be in the SIP are contained in a 

presentation given by Brenda Johnson at the EPA Region 4 State and Local Modelers 

Workshop held in March 2007. This presentation may be accessed on the following 

website: http://www.epa.gov/region4/air/modeling/workshop.htm 

7. Scenarios modeled: It is unclear how the different combinations of controls were 

determined for the seven scenarios modeled for the BART determination. Were other 

combinations also considered? This discussion could be included in chapter 4.0. 

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Appendix L.8 - 385

January 18, 2008
Attachment A 

Excerpt from August 24, 2006 Q&A Document 

4. How should a State document in the SIP that BART controls will be installed and 

in operation as expeditiously as practicable, but no later than 5 years after 

approval of the SIP? Must BART controls be housed in a Title V permit 

modification? 

As specified in 40 CFR 51.308(e)(1)(v), States are required to ensure each source 

subject to BART install and operate BART as expeditiously as practicable, but in 

no event later than 5 years after approval of the implementation plan revision. 

States should ensure that BART requirements in a SIP are written in a way that 

clearly specifies the individual emission unit(s) subject to BART regulation and 

the time by which the emission unit(s) must begin to comply with the BART 

limit. Because the BART requirements are ‘‘applicable’’ requirements of the 

CAA, they must be included as title V permit conditions according to the 

procedures established in 40 CFR part 70 or 40 CFR part 71. Under 70.7(f)(1)(i) 

Title V permits must be reopened and revised to include new applicable 

requirements if the permit has three or more years of life. The reopening must be 

completed within 18 months after promulgation of the new applicable 

requirement and the reopening must follow the same procedures (public 

comment, etc) as apply to initial permit issuance. This may require that States 

provide commitments in the SIPs to ensure that all applicable construction 

permits under Title 1, and the operating permits under Title V are revised in time. 

The following elements, at a minimum, must be addressed to ensure the BART 

controls are adopted into the State’s SIP. These elements are discussed in detail 

with other circumstances in 40 CFR Part 51, Appendix Y – Section V. 

• Name of source facility and the specific emission units and pollutants 

being controlled. (40 CFR 51.308(e)(1)(i) & (ii)). 

• Specifics of the controls, control efficiency(ies), emissions reductions 

expected 

• Enforceable emission limitations representing BART (40 CFR 

51.308(d)(3);(e)) 

• Schedules for compliance with BART (40 CFR 51.308(d)(3);(e)) 

• A requirement that each source subject to BART maintains the control 

equipment and establish procedures to ensure such equipment is properly 

operated and maintained. (40 CFR 51.308(e)(v)) 

• Reporting, monitoring, and recordkeeping requirements adequate to 

determine the source’s compliance (40 CFR Part 51, Appendix Y – V). 

• Averaging times and reference methods to determine compliance (40 

CFR Part 51, Appendix Y – V). 

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January 18, 2008
ATTACHMENT B 

U.S. EPA Region 4 Review of the VISTAS Methodology for Implementing the 

New IMPROVE Equation with CALPUFF for BART Modeling 

The original Interagency Monitoring of Protected Visual Environments (IMPROVE) 

algorithm for estimating light extinction from particle speciation data tends to 

underestimate light extinction for the highest haze conditions and overestimate it for the 

lowest haze conditions. It uses a ratio of organic compound mass to carbon mass of 1.4, 

though the literature indicates that the ratio is higher especially in remote areas. It also 

does not include a term for sea salt, which is important at sites near the ocean coasts. As 

a result of these limitations, the IMPROVE Steering Committee commissioned the 

development of a new IMPROVE algorithm, which they adopted for use in December 

2005. It is our understanding that some sources want to use the new IMPROVE 

equation to take advantage of sea salt and site-specific Rayleigh scattering for BART 

modeling in Region 4. A new methodology is needed to process the mass concentrations 

from CALPOST using the new IMPROVE equation so that the Best Available Retrofit 

Technology (BART) analyses could consider both the old and new IMPROVE equations. 

The U.S. Environmental Protection Agency (EPA) and the Federal Land Managers 

(FLMs) from the National Park Service and the U.S. Fish and Wildlife Service have 

determined that adding site-specific data (e.g. sea salt and site-specific Rayleigh 

scattering) in the old IMPROVE equation, for a hybrid approach is not recommended. A 

methodology to post-process CALPUFF/CALPOST data to implement the entire new 

IMPROVE equation with CALPUFF is needed. The new IMPROVE equation cannot be 

directly implemented using the existing version of the CALPUFF model without 

additional post-processing or model revision. The Visibility Improvement - State and 

Tribal Association for the Southeast (VISTAS) tasked Dr. Ivar Tombach to develop such 

a methodology. The State of North Carolina submitted a request for the review of this 

methodology to EPA and the FLMs. 

The VISTAS methodology for implementing the new IMPROVE equation using existing 

CALPUFF/CALPOST output is contained in a spreadsheet developed by Dr. Ivar 

Tombach. The VISTAS procedure is essentially a modification of CALPOST, which 

provides the calculations of the light extinction from the CALPUFF output. This 

proposed VISTAS methodology constitutes a non-regulatory modeling application 

requiring compliance with section 3.2 of Appendix W, Part 51: Guideline on Air Quality 

Models. Requests for using this alternative method should be made by each individual 

State allowing time for EPA Region 4 approval prior to the public hearing on the State’s 

Regional Haze State Implementation Plan (SIP) submittal. A generic approval for all 

applications of this alternative method will not be provided. EPA approval will be 

granted on a case-by-case basis, considering the merits of the State’s request including 

supporting documentation for using the alternative methodology for the BART modeling.

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January 18, 2008
Documentation to support the use of the VISTAS methodology is needed and should 

include the following. 

 

- A rationale for why the new IMPROVE equation is needed for the application 

(e.g., the old IMPROVE algorithm does not account for the impact of sea salt on 

background conditions which can be important for coastal sites);

- An evaluation, specific to the Class I Areas being examined for the modeling 

demonstration, of the new vs. old equations performance when compared to 

measured/monitored values (e.g., as provided in "Revised IMPROVE Algorithm 

for Estimating Light Extinction from Particle Speciation Data" found on 

http://vista.cira.colostate.edu/IMPROVE/Publications/GrayLit/019_RevisedIMPR

OVEeq/RevisedIMPROVEAlgorithm3.doc ); and

- A detailed description of the procedures used in the modified-post processing 

methodology (e.g., spreadsheet or other post-processing calculations with explicit 

discussion on the limitations and assumptions in developing the data inputs).

 

Additionally, consistency should be maintained when applying the new vs. old equations 

when calculating natural background, current, and future visibility impacts at Class I 

Areas. For example, if the new IMPROVE equation is used to calculate the natural 

background visibility impact for a Class I area for the BART modeling, the new 

IMPROVE equation should also be used to calculate the BART source’s current and 

future impact on visibility. 

The VISTAS methodology contained in the spreadsheet developed by Dr. Ivar Tombach 

appropriately implements the features of the new IMPROVE equation, with the exception 

of the nitrogen dioxide term. The methodology provides an adequate procedure for 

calculating the bimodal split for sulfates, nitrates and organics. This is accomplished by 

following the procedures for calculating the large and small fractions based on a 

concentration cutpoint of 20 ug/m3 , as recommended in the technical support document 

for the new IMPROVE algorithm ("Revised IMPROVE Algorithm for Estimating Light 

Extinction from Particle Speciation Data" found on 

http://vista.cira.colostate.edu/IMPROVE/Publications/GrayLit/019_RevisedIMPROVEeq

/RevisedIMPROVEAlgorithm3.doc). The methodology also incorporates the new sizefraction specific f(RH) factors contained in the technical support document. These new 

procedures are used to calculate the visibility impacts from the source and also to adjust 

natural background values (to account for sea salt and the bimodal split of sulfates, 

nitrates and organics). The background value is appropriately added to the source 

concentration for determining the correct size fraction for sulfates, nitrates and organics. 

The calculated visibility impacts are then compared with the adjusted natural background 

visibility to determine the change in visibility impact for the comparison with the 

threshold value. 

As noted above, the methodology does not adequately address the nitrogen dioxide (NO2) 

term in the new IMPROVE equation. It indicates that the NO2 term is small and 

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January 18, 2008
insignificant. This may not be the case in each specific application. NO2 concentrations 

are not readily available from CALPUFF/CALPOST when using the default MESOPUFF 

II chemistry option. Therefore, EPA Region 4 has determined that it would be 

acceptable to use the total NOx concentration as a surrogate for NO2 (i.e., conservatively 

assume that all NOx is NO2). The total NOx concentration can easily be obtained by 

turning on the switch to produce NOx concentration output when running CALPOST– no 

changes to the CALPUFF modeling are needed. The NOx concentration is obtained in 

CALPOST using the following option in Input Group 1 of the CALPOST Input File: 

! ASPEC = NOX !. With the addition of this recommendation for addressing the NO2 

term, we believe the VISTAS methodology to incorporate the new IMPROVE equation is 

acceptable on a case-by-case basis and upon consultation with the EPA Regional Office. 

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January 18, 2008
Alcoa 

Tennessee Operations 

2300 North Wright Road a

Alcoa, TN 37701-3141 USA

January 10, 2008 

Mr. Barry Stephens, Technical Secretary 

Tennessee Division of Air Pollution Control 

9th Floor, L & C Annex 

401 Church Street 

Nashville, Tennessee 37243-1531 

Re: Response to Comments on the Best Available Retrofit Control Technology 

Analysis for Alcoa, Inc. Tennessee Operations; Alcoa, Tennessee 

Dear Mr. Stephens: 

As requested by the Tennessee Division of Air Pollution Control (TDAPC), Alcoa Inc. – 

Tennessee Operations (Alcoa) is submitting the attached responses to specific 

comments received on the best available retrofit control technology (BART) analysis 

during the recent public comment period. 

We look forward to working alongside the TDAPC to finalize the regional haze state 

implementation plan. If you require additional information, please contact me at the 

address above or by phone at (865)-977-2403. 

Sincerely, 

Chris Moore 

Environmental Engineer 

Alcoa Inc. - Tennessee Operations 

 
USEPA Region IV Comments 

Enclosure 1: Control and Cost Analyses 

1. The declaration that the use of coke at less than 3 percent sulfur content 

is infeasible will require extensive supporting documentation, since coke 

suppliers can produce coke with a sulfur content as low as 0.25 percent. 

Alcoa Response: A detailed market analysis discussing this declaration 

was included as confidential business information (CBI) in the original 

BART Analysis submitted to the TDAPC. A summary of this analysis 

without CBI is included as follows: 

In the processing of crude oils, refineries are left with a residual material 

made up of high molecular weight hydrocarbons. This residual material or 

“resid” can either be sold into the low value fuel market or upgraded into 

higher value products than the starting resid. A delayed coker is used to 

heat resid to the temperature and resonance time needed to further 

polymerize and crack the resid into coke (by-product) and produce lighter 

fraction liquids that can be further distilled into higher value products (e.g. 

gas, gasoline, gas oils, etc.). 

The four types of coke produced from a delayed coker are: 

• Fuel grade coke 

• Sponge coke 

• Needle coke 

• Shot coke 

The aluminum industry requires a coke that provides an appropriate 

coefficient of thermal expansion (CTE) and an acceptable level of porosity. 

An appropriate CTE is important because too high of a CTE results in 

crack formation within the anode. Cracks in the anode produce a higher 

numbers of broken anodes and higher electrical resistance. Increased 

frequency of carbon breakage increases labor costs, increases raw 

material costs, increases the number of anodes that must be prematurely 

replaced in the cells, and decreases current efficiency. Low CTE 

produces undesirably higher resistance to gaseous oxidation, and lower 

electrical resistivities of the coke particles. Porosity of the coke impacts 

the mechanical strength of the final anode. Needle cokes and Shot cokes 

are on the two extremes of porosity, and their use produces unsuitable 

anodes with respect to CTE and mechanical strength. Therefore a coke of 

intermediate porosity is needed to produce anodes with an acceptable 

CTE and with acceptable density and mechanical strength. The 

characteristics of a calcined coke essential to producing a good quality 

anode are, 1) low impurity concentrations, 2) appropriate sulfur content, 3) 

Page 2 of 12 
sufficient vibrated bulk density, 4) appropriate coke structure (quantity, 

size, and shape of pores), and 5) appropriate microtexture. Of the four 

cokes produced from a delayed coker, sponge coke is the most suitable to 

the production of anodes for the aluminum industry. 

The demand for highly refined (light fraction) petroleum products is 

estimated to continue growing annually. To meet demand, producers are 

expected to revamp existing refineries and construct new refineries that 

maximize light product yields from high sulfur crudes, allowing refiners to 

capitalize on the significant price difference between high and low sulfur 

crude oils. The current price differential between high and low sulfur 

crude oils is already driving existing anode coke producing refineries to 

maximize their intake of sour (i.e. high sulfur ) crude. The net result of this 

has been a steady increase in sulfur level in anode grade coke. 

The calcined coke used by the aluminum industry is a small portion of the 

product profile of the oil refineries. In 2005 worldwide anode grade 

calcined coke consumption represented 0.37% of the worldwide crude oil 

production. This extremely small percentage of product profile and the 

value delivered to the oil refineries from selling coke limits the ability of the 

aluminum industry to influence the product quality of the green petroleum 

coke. As such, the aluminum industry has little influence in controlling the 

quantity, quality, and the price of the coke produced by refineries 

Page 3 of 12 
The deterioration in coke quality and the tightness of supply is expected to 

continue for the foreseeable future. As a result, Alcoa’s Tennessee 

smelter is unable to guarantee compliance with a coke sulfur content of 

less than 3%, because the future availability and cost of anode grade coke 

with less than 3% sulfur cannot be assured. 

Page 4 of 12 
USEPA Region IV Comments 

Enclosure 2: Modeling Analyses 

General Comments on the Modeling Documentation and for the State

1. Source emission and stack data: One of the most important factors in any 

modeling exercise is to ensure that the source parameters (e.g., emission rates, 

stack parameters) are correct. EPA Region 4 recommends that the State 

carefully compares the model input parameters with existing permits, databases, 

etc. to ensure that appropriate values are being used for the BART modeling. 

Alcoa Response: All stack emissions data and modeling input bases were 

clearly delineated in the modeling protocol. 

2. Deciview Threshold and Modeling exemption: The exemption threshold value 

selected by the State in determining whether a BART-eligible source can 

reasonably be anticipated to cause or contribute to visibility impairment must be 

documented in the State Implementation Plan (SIP), as must the basis for the 

States' selection of this threshold. The threshold should be no higher than 0.5 

delta deciview (dv) (e.g. >/= 0.5 is subject to BART, < 0.5 is exempt per the 

BART guidelines). In establishing the threshold, States should consider the 

number of emission sources affecting the Class I Areas at issue, the magnitude 

of the sources' impacts, and the location of the sources. (See 70 FR 39161-

39162, July 6, 2005.) The appropriateness of the threshold used by the State will 

be subject to public review and comment, and States could consult with the 

affected States or Regional Planning Organizations or Federal Land Managers in 

establishing this value. 

Alcoa Response: Alcoa assumes the TDAPC will address this comment. 

3. BART-Eligible Units: We suggest that the documentation for the BART SIP 

requirements include a list of all emission units at the ALCOA facility which 

includes dates of operation, existence, pollutants and potential emissions. The 

list or table containing all of the Alcoa emission units would illustrate why each 

emission unit was or was not considered BART eligible. If BART-eligibility is 

based on specific dates and later determined otherwise, that reason should also 

be presented. 

Alcoa Response: The basis for BART-eligibility for each emission unit is 

included in the BART Analysis. 

 
Specific Modeling Comments 

1. Section 3.1, page 3-4: 

 a. The submittal states that Potlines 1 and 2 and the anode bake furnace are 

already equipped with sophisticated emission control equipment for PM, so the 

BART determination for these emission units focuses primarily on potential 

reductions for S02 and NOx. The submittal should also discuss why the 

"sophisticated emission controls" represent BART controls. The use of term 

sophisticated controls does not adequately justify this assumption. 

Alcoa Response: These controls are discussed in the BART Analysis. 

 b. The submittal also indicates that the remaining 21 units in Table 1 have 

baghouses to control PM emissions and that the baghouses represent the best 

available control for these units. Since the emissions from these units are 

claimed to be insignificant, it is important to assure that the emissions controls 

are operated properly. Therefore, the BART determination should ensure that 

there are permit conditions requiring the baghouses to be properly operated and 

maintained. 

Alcoa Response: Permit conditions for these emission units requiring proper 

operation and maintenance are already included in the applicable Title V air 

permit. 

2. CALPOST Method 8 

c. Light extinction was calculated in a version of the CALPOST postprocessor 

that utilizes the new IMPROVE equation using a new method called Method 8. 

The submittal states that Method 8 provides a better correspondence between 

the measured visibility and that calculated from pollutant concentrations 

simulated by the model. This model change is not the Visibility Improvement -

State and Tribal Association of the Southeast (VISTAS) model that has been 

agreed upon for use in the BART modeling. It has not been sufficiently and 

clearly demonstrated that the new CALPOST provides a better method to 

incorporate the new IMPROVE equation into the CALPUFF modeling system. In 

order to use a version other than the agreed upon version, adequate 

documentation must be included. 

Alcoa Response: Alcoa assumes this issue will be addressed by the TDAPC as 

it is our understanding that the new IMPROVE equation was approved for use by 

VISTAS because it is more accurate. In any case, the Final Modeling Report in 

Appendix B of Alcoa’s BART Determination Report provides visibility impact 

results based on both the OLD (Method 6) and NEW (Method 8) IMPROVE 

equations. Visibility impact results predicted by Method 8 are slightly lower than 

Method 6 as summarized in the table below. However, this difference is not 

sufficient to change any conclusions regarding Alcoa’s BART determination. 

Page 6 of 12 
Modeled 98th Percentile (deciviews) 

Class 1 Area Method 6 Method 8 

1.273 1.092 

Great Smoky Mountains 1.189 0.966 

1.620 1.310 

0.385 0.301 

Linville Gorge 0.446 0.363 

0.475 0.370 

0.462 0.375 

Shining Rock 0.493 0.463 

0.359 0.293 

0.511 0.474 

Joyce-Kilmer/ Slickrock 0.677 0.549 

0.837 0.686 

0.499 0.427 

Cohutta 0.413 0.335 

0.492 0.414 

d. There is no documentation on how the version of CALPOST with Method 8 

was developed. Quality assurance that was used in its development, coding and 

integration of the new equation with CALPUFF to develop visibility impacts was 

not discussed. 

Alcoa Response: Details on the CALPOST calculation are provided in the Final 

Modeling Report (Appendix B of the BART Determination Report). The 

CALPOST code with Method 8 was submitted to the Federal Land Managers 

(John Vimont, John Notar) on October 2, 2007 for their review. As noted in the 

report, the CALPOST Method 8 calculation is consistent and equivalent with the 

spreadsheet method prepared by Ivar Tomback that has been reviewed and 

approved by the FLMs and EPA. 

e. It is incumbent upon the state and the facility to ensure that this new model is 

developed and documented in an appropriate and detailed manner, suitable for 

use in the BART modeling and review by EPA. 

Alcoa Response: Please see response provided for Question 2c. 

f. CALPOST Method 8 sets the maximum relative humidity at 98 percent by 

default but the user can change it. EPA guidance caps the relative humidity at 95 

percent. 

 

 i. What relative humidity was used in the Alcoa BART modeling? 

Page 7 of 12 
Alcoa Response: As indicated on Page 4-12 of the modeling report, with 

Method 6, the monthly f(RH) values were based on Appendix A of Guidance for 

Estimating Natural Visibility Conditions Under the Regional Haze Program 

(September 2003). Table 4-4 in the modeling report lists the specific values of 

f(RH) used in the analysis. The Appendix of the modeling report contains a 

detailed description of the new IMPROVE equations implemented as Method 8 in 

CALPOST. Figure 1 of the Appendix contains the species-dependent f(RH) 

curves used with Method 8. 

 ii. Why was the maximum relative humidity changed when the EPA 

guidance caps it at 95 percent? 

Alcoa Response: In the CALPOST input files and output list files, it can be seen 

that RHMAX=95, but in any case, the maximum humidity is not relevant in this 

case because monthly average relative humidity based on the r(RH) values in 

Table 4-4 was used with Method 8. The IMPROVE (2006) humidity curves were 

applied for sea salt and small and large nitrate and sulfate particles. The method 

used here is consistent with Ivar Tomback’s spreadsheet approach. 

 iii. Documentation should indicate which f(RH) curve (i.e., December 2000 

Flag report, EPA f(RH) curve or IWAQM 1998 f(RH)was used in the modeling. If 

something other than that recommended in the VISTAS modeling protocol was 

used, an explanation is required. 

Alcoa Response: A disk with model input and output files was provided to 

TCAPC as part of the March 2007 BART submittal. Details on relative humidity 

curves and assumptions are discussed in the Final Modeling Report (Appendix B 

of the BART Determination Report). Also, please see response provided for 

questions i and ii above and Question 2c. 

g. What is the background and rationale to support the new f(RH) curves that are 

incorporated in the CALPOST Method 8 processor? 

Alcoa Response: The method is based on the new IMPROVE methodology as 

implemented in Ivar Tombach’s spreadsheet and described in the journal paper 

Pitchford et al. (2007), Revised Algorithm for Estimating Light Extinction from 

IMPROVE Particle Speciation Data, JAWMA, 57, 1326-1336. 

h. The level of independent review, the CALPOST Method 8 processor has 

undergone in its development and implementation should be discussed. 

Alcoa Response: Please see response provided for Question 2c. 

i. The new IMPROVE equation coupled with the modified CALPOST processor is 

not a generic model that EPA Region 4 recognizes to be a part of the CALPUFF 

modeling system. Its use should be justified on a case-by-case basis. A detailed 

Page 8 of 12 
justification, which addresses the rationale for using the new equation and the 

performance of the new equation versus the old equation should be provided. 

Attachment B provides EPA Region 4's review of the use of a spreadsheet 

developed by the Visibility Improvement State and Tribal Association for the 

Southeast (VISTAS) with CALPUFF that could be used if the appropriate 

documentation to support the modified CALPOST model is not available. 

Alcoa Response: The Method 8 calculation in CALPOST is consistent and 

equivalent to the spreadsheet. It was coded to allow the spreadsheet results to 

be closely matched in a much more efficient manner than the manual 

manipulations required for the spreadsheet, especially when multiple years of 

data and multiple Class I areas are involved. 

j. Nitrogen dioxide concentrations: The report does not discuss the origin of the 

N02 data used in CALPOST. EPA Region 4 has determined that it would be 

acceptable to use the total NOx concentration as a surrogate for N02 (i.e., 

conservatively assume that all NOx is N02). The total NO x concentration can 

easily be obtained when running CALPOST by turning on the switch to produce 

NOx concentration output -no changes to the CALPUFF modeling are needed. 

Alcoa Response: As indicated on Page 4-13 of the report, the NO2 is based on 

NOx with a NO2/NOx ratio of 1, meaning the assumption is NO2 = NOx. 

k. Sea Salt: Documentation on how sea salt concentrations were developed and 

used with the new IMPROVE equation and the BART modeling was not, but 

should be, explicitly discussed in the submittal. 

Alcoa Response: The values used for the Class I areas were based on the 

recommendations on the Rayleigh and Sea Salt tab of Ivar Tombach’s 

spreadsheet. 

j. Referencing a method to use the new IMPROVE equation as developed 

through a paper funded by VISTAS does not provide the documentation needed 

to support the modeling. Documentation of the method used to incorporate the 

new IMPROVE equation should be provided. 

Alcoa Response: See the journal paper Pitchford et al. (2007) referenced 

above. Also, note the comments regarding the equivalence of the spreadsheet 

method implementing the new IMPROVE equations with the CALPOST Method 

8. 

3. CALMET: 

The report on page 4-3 states that I-kilometer (km) grid resolution modeling was 

used in the refined modeling of the facility. The documentation on the 

development of the l-km meteorological data using CALMET was incomplete. 

The documentation should discuss the CALMET input options used to develop 

Page 9 of 12 
the data and the performance assessment and quality assurance used to review 

the data for accuracy and usefulness. Descriptions of the model are provided 

with options that could be used. However details on what were used in 

developing the meteorological data is required in the submittal. 

Alcoa Response: Details on development of the 1-km grid as well as CALMET 

input options are discussed in modeling protocol submitted to TDAPC on June 

30, 2006 and in the Final Modeling Report (Appendix B of the BART 

Determination Report). No comments were received from TDAPC on these 

submittals. Also note that the entire CALMET input file was provided in the 

electronic submittal provided to the state on March 3, 2007. 

4. CALPUFF Results 

Table 8 on page 5-25 of the report presents the CALPUFF modeling results for 

two control scenarios. Control Scenario 2 is listed as "3.0% Sulfur Coke." Based 

on the modeling results presented in Tables 5-1 through 5-14 in Appendix B of 

the report, the results for Control Scenario 2 are really the modeling results for 

the baseline "Base Case Run." Table 8 should be revised to indicate that "3.0% 

Sulfur Coke" is the "Base Case" as it represents the current operation. 

Alcoa Response: In preparing the BART analysis, Alcoa considered the use of 

3.0% sulfur coke to be a “Control Scenario” because, as discussed on page 5-8 

of the Report, the facility’s current practical limit on SO2 emissions (potential to 

emit) is based on 3.5% sulfur coke. 

Appendix B of the Submittal 

1. Page 4-11: The first sentence on this page states that "each source is modeled 

by group of the same emission rates and their source contributions are summed 

at the end" to provide for flexibility. It is unclear what the "group of same 

emission rates" is referencing. 

Alcoa Response: This sentence should read: “To allow for flexibility each 

source was modeled either individually or grouped with similar sources, and 

individual or group contributions were summed at the end.” 

2. Even though the submittal indicates that the modeling supposedly produced 

delta visibility impacts at Mammoth Cave that were less than 0.5 deciviews, the 

modeling results should be presented. 

Alcoa Response: The screening model results for Mammoth Cave are 

reported in the Modeling Protocol submitted to the TDAPC on June 30, 2007 

(Appendix A of the BART Determination Report). 

Page 10 of 12 
3. Tables 5-1 through 5-12 should be consistent in how the modeling results are 

presented. All of the top eight delta visibility impacts should be presented for 

Linville Gorge, Shining Rock, and Cohutta. 

Alcoa Response: Alcoa did not report all of the top eight visibility impact 

values whenever the impacts fell below the 0.5 dv exemption threshold. 

4. The State should document in the Regional Haze SIP why the 0.5 visibility 

threshold was applicable for the BART exemption modeling. The State should 

also document whether a 0.5 dv threshold should be used to determine visibility 

improvement for tile BART determination modeling. 

Alcoa Response: Alcoa assumes the TDAPC will respond to this comment. 

5. It is unclear what version of CALMET, CALPUFF, and the other processors 

were used in the BART modeling. 

Alcoa Response: The VISTAS versions of the CALMET and CALPUFF model 

codes were used in the modeling, consistent with the protocol submitted in June 

2006. More specifically, following VISTAS versions, which were the current 

VISTAS recommended codes at the time of the simulations, were used: 

 CALMET Version 5.724, Level 060414 

CALPUFF Version 5.754, Level 060202 

POSTUTIL Version 1.52, Level 060412 

CALPOST Version 5.6393, Level 060202 for Method 6 

CALPOST Version 6.141, Level 061120 for Method 8 

Page 11 of 12 
National Park Service Comment 

1. Don Shepherd of the National Park Service made the following comment via 

email to Quincy Styke of the TDAPC referring to the BART Analysis for Columbia 

Falls Aluminum Company (CFAC) in Columbia Falls, Montana: 

“On pages 4-5 and 4-10 to 4-13, CFAC discuss switching from its 

current 1.5% S coke to coke with as little as 0.5% S. I would 

appreciate it if you could investigate this possibility with ALCOA and 

let me know what you find out.” 

Alcoa Response: See previous comment response to the USEPA Region IV on 

Page 2 of 10. Additionally, note that the CFAC facility and Alcoa Inc. Tennessee 

Operations employ different smelting processes. 

 












Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 390

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 391

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 392

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 393

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 394

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 395

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 396

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 397

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 398

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 399

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 400

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 401

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 402

January 18, 2008
Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 403

January 18, 2008
TVA Response to Regional Haze Comments - TN 

• The cost of material under the annual cost of the wet ESP is higher than what 

is normally expected for this type of control device. How did the source 

determine this number? Please justify that it will cost approximately $787,610 

to purchase materials for this control device. 

As stated in Section II of the TVA BART analysis report under “Cost of Compliance” 

(page 3), “...annual costs were based on information in the EPA Air Pollution 

Control Cost Manual, Sixth Edition.” The basis for the maintenance material costs is 

shown in Table 2 (page 5). The source assumed the material costs are approximately 

1 percent of the purchased equipment cost, which is an EPA assumption for ESPs 

taken from the referenced EPA cost manual. 

• The estimated cost of waste disposal to a wet ESP is extremely high and not 

what EPA would normally consider an adequate waste disposal estimate for 

this type of control device. How did the source determine this cost estimate? 

Where is the waste going or is it to be treated off site?

As stated in Section II of the TVA BART analysis report under “Non-air 

Environmental Impacts” (page 3), “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.” So the 

quantity of waste water generated was estimated based on this EPA assumption. As 

shown in Table 2 (page 5), the cost of disposal was assumed to be $2/1000 gal, which 

comes from the same EPA cost manual. 

• EPA recognizes that the facility considers the cost of installing a wet ESP for 

this boiler economically infeasible. Did the applicant, however, consider 

enhancing the existing dry ESP in order to achieve better capture of PM10?

The existing ESPs at TVA Cumberland Fossil Plant consistently perform with 

excellent capture efficiencies. Recent compliance tests showed particulate emission 

levels of 0.007 lbs/MMBtu for Unit 1 and 0.004 lbs/MMBtu for Unit 2. It would not 

be cost effective to attempt to improve on this performance. 

• Section 10.0 Interstate Consultation Please clarify in the following statement 

whether the Gallatin plant is expected to be controlled by 2018: "TVA has 

indicated that it will ultimately control Gallatin if needed, and either repower or 

shut down the Johnsonville facility by the next review period in 2018". 

TVA has developed a comprehensive clean air plan based on compliance with Phases 

I and II of CAIR and CAMR that will involve installation of substantial additional 

controls on various units across their system into the next decade. These controls are 

in addition to those already installed and currently under construction. To ensure that 

TVA makes the best economic decisions for its rate payers this plan is, by 

necessity, subject to continuous review and update in response to changes in load 

forecasts, fuel and allowance price forecast changes, changing market conditions, 

new regulations and a variety of other factors. Phase II CAIR requirements will drive 

TVA to make further reductions on their system by re-powering, additional fuel 

switching, installing additional controls on units such as Gallatin or others, or 

possibly shutting down units, but it is too soon to determine exactly which mix of 

options on which specific units provides the optimum compliance strategy. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 404

January 18, 2008
STATE OF TENNESSEE 

DEPARTMENT OF ENVIRONMENT AND CONSERVATION 

DIVISION OF AIR POLLUTION CONTROL 

9th Floor, L & C Annex 

401 Church Street 

Nashville, Tennessee 37243-1531 

CERTIFIED MAIL 7004 0550 0000 9791 4636 

 RETURN RECEIPT REQUESTED 

May 4, 2006 

 

Mr. Chris Moore 

Sr. Staff Environmental Engineer 

Alcoa Inc. – Tennessee Operations 

2300 North Wright Road 

Alcoa, TN 37701-3141 

Reference Number: 05-0008-G1 

Dear Mr. Moore: 

As you know, the United States Environmental Protection Agency (EPA) published the final Regional Haze 

Regulations and Guidelines for Best Available Retrofit Technology (BART) in the Federal Register on July 6, 2005, 

(70 FR 39104). This final rule requires that the State of Tennessee (“State”) submit a State Implementation Plan 

(“SIP”) for regional haze by December 17, 2007. The SIP must contain emission limitations representing BART 

and schedules for compliance with BART for each BART-eligible source that may reasonably be anticipated to 

cause or contribute to any impairment of visibility in any mandatory Class I Federal area. In order to fulfill the 

SIP requirement, a BART determination must be conducted for each BART-eligible source at your facility. 

Appendix Y to 40 CFR 51 contains guidelines for the BART determination process. 

Step 1. Identification of BART-eligible sources: 

Based on the criteria specified in Appendix Y, the State has identified the BART-eligible sources located at your 

facility. Please contact Julie Aslinger if you have questions regarding which sources at your facility have been 

identified as BART-eligible. 

Step 2. Identification of sources “subject to BART”: 

The State has determined that the sources identified as BART-eligible at your facility are subject to BART. You are 

required to proceed with the BART determination process. However, you are free to pursue your own exemption 

modeling. If you choose to perform your own exemption modeling, you must submit an exemption modeling 

protocol to the State with thirty (30) days of receipt of this letter. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 405

January 18, 2008
Page 2 

Mr. Chris Moore 

May 4, 2006 

Step 3. BART determination (Analysis of BART options): 

The third step of the BART process is the analysis of BART control options. This step requires selection of 

technically feasible, cost effective control technologies and use of the CALPUFF Model to determine the expected 

visibility improvement. Note that Appendix Y contains specifics for determining what types of BART emission 

control options are feasible, if existing emissions controls are adequate for BART, or if no emission controls are 

feasible. See below for BART determination submittal deadlines. 

Step 4. Enforceable limits/compliance date 

The fourth step of the BART process is for the State to establish enforceable emission limits that reflect the BART 

requirements and assure that compliance with these limitations is achieved by the date specified in Appendix Y. The 

current compliance date is specified as no later than five (5) years after approval of Tennessee’s SIP by EPA. 

Following approval of your BART determination, it may be necessary to modify your current Air Pollution Control 

operating permit. 

In order for the State to meet the SIP submittal deadline of December 17, 2007, the following deadlines for required 

submittals have been established: 

June 30, 2006 – Submit site-specific modeling protocol 

Summer 2006 – Conduct BART determination 

November 1, 2006 – Submit BART determination, including CALPUFF modeling results 

VISTAS BART Resources 

VISTAS has been developing several resources that may be useful to BART eligible sources including the 

“VISTAS Protocol for the Application of the CALPUFF Model for Analyses of Best Available Retrofit Technology 

(BART)”, 12 km CALMET (CALMET is a meteorological data processing module associated with the CALPUFF 

model) Data, VISTAS subdomains for refined modeling, 4 km CALMET Data, a VISTAS version of CALPUFF and 

associated documentation, an example application of CALPUFF for BART purposes, and CALMET and CALPUFF 

input files. With the exception of the CALMET data sets, most of these items are available on the BART portion of 

the VISTAS website, located at www.vistas-sesarm.org/BART. To obtain the 4 km or 12 km CALMET data sets 

which are currently available, please contact Julie Aslinger at (615) 532-0587 or Julie.Aslinger@state.tn.us. The 

CALMET data sets are rather large. For data transfer purposes, you will need to provide an appropriate size fire 

wire or USB drive onto which the data will be copied. You must also include a prepaid and addressed postage label 

for shipping the drive back to you. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 406

January 18, 2008
Page 3 

Mr. Chris Moore 

May 4, 2006 

If you have questions concerning this correspondence, or if you require additional information concerning the BART 

process, please contact Ms. Julie Aslinger at (615) 532-0587. 

Sincerely, 

Barry R. Stephens, P.E. 

Director 

Tennessee Division of Air Pollution Control 

cc: Knoxville Environmental Field Office 

 05-0008-G1 

 05-0008 BART File (JA) 

 Green File 

 Certified File 

 BRS 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 407

January 18, 2008
STATE OF TENNESSEE 

DEPARTMENT OF ENVIRONMENT AND CONSERVATION 

DIVISION OF AIR POLLUTION CONTROL 

9th Floor, L & C Annex 

401 Church Street 

Nashville, Tennessee 37243-1531 

CERTIFIED MAIL 7004 0550 0000 9791 4575 

 RETURN RECEIPT REQUESTED 

May 4, 2006 

 

Mr. David H. Brau 

E I DuPont de Nemours& Company, Inc. 

1002 Industrial Drive 

Old Hickory, TN 37138 

Dear Mr. Brau: 

As you know, the United States Environmental Protection Agency (EPA) published the final Regional Haze 

Regulations and Guidelines for Best Available Retrofit Technology (BART) in the Federal Register on July 6, 2005, 

(70 FR 39104). This final rule requires that the State of Tennessee (“State”) submit a State Implementation Plan 

(“SIP”) for regional haze by December 17, 2007. The SIP must contain emission limitations representing BART 

and schedules for compliance with BART for each BART-eligible source that may reasonably be anticipated to 

cause or contribute to any impairment of visibility in any mandatory Class I Federal area. In order to fulfill the 

SIP requirement, a BART determination must be conducted for each BART-eligible source at your facility. 

Appendix Y to 40 CFR 51 contains guidelines for the BART determination process. 

Step 1. Identification of BART-eligible sources: 

Based on the criteria specified in Appendix Y, the State has identified the BART-eligible sources located at your 

facility. Please contact Julie Aslinger if you have questions regarding which sources at your facility have been 

identified as BART-eligible. 

Step 2. Identification of sources “subject to BART”: 

The State has determined that the sources identified as BART-eligible at your facility are subject to BART. You are 

required to proceed with the BART determination process. However, you are free to pursue your own exemption 

modeling. If you choose to perform your own exemption modeling, you must submit an exemption modeling 

protocol to the State with thirty (30) days of receipt of this letter. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 408

January 18, 2008
Page 2 

Mr. David H. Brau 

May 4, 2006 

Step 3. BART determination (Analysis of BART options): 

The third step of the BART process is the analysis of BART control options. This step requires selection of 

technically feasible, cost effective control technologies and use of the CALPUFF Model to determine the expected 

visibility improvement. Note that Appendix Y contains specifics for determining what types of BART emission 

control options are feasible, if existing emissions controls are adequate for BART, or if no emission controls are 

feasible. See below for BART determination submittal deadlines. 

Step 4. Enforceable limits/compliance date 

The fourth step of the BART process is for the State to establish enforceable emission limits that reflect the BART 

requirements and assure that compliance with these limitations is achieved by the date specified in Appendix Y. The 

current compliance date is specified as no later than five (5) years after approval of Tennessee’s SIP by EPA. 

Following approval of your BART determination, it may be necessary to modify your current Air Pollution Control 

operating permit. 

In order for the State to meet the SIP submittal deadline of December 17, 2007, the following deadlines for required 

submittals have been established: 

June 30, 2006 – Submit site-specific modeling protocol 

Summer 2006 – Conduct BART determination 

November 1, 2006 – Submit BART determination, including CALPUFF modeling results 

VISTAS BART Resources 

VISTAS has been developing several resources that may be useful to BART eligible sources including the 

“VISTAS Protocol for the Application of the CALPUFF Model for Analyses of Best Available Retrofit Technology 

(BART)”, 12 km CALMET (CALMET is a meteorological data processing module associated with the CALPUFF 

model) Data, VISTAS subdomains for refined modeling, 4 km CALMET Data, a VISTAS version of CALPUFF and 

associated documentation, an example application of CALPUFF for BART purposes, and CALMET and CALPUFF 

input files. With the exception of the CALMET data sets, most of these items are available on the BART portion of 

the VISTAS website, located at www.vistas-sesarm.org/BART. To obtain the 4 km or 12 km CALMET data sets 

which are currently available, please contact Julie Aslinger at (615) 532-0587 or Julie.Aslinger@state.tn.us. The 

CALMET data sets are rather large. For data transfer purposes, you will need to provide an appropriate size fire 

wire or USB drive onto which the data will be copied. You must also include a prepaid and addressed postage label 

for shipping the drive back to you. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 409

January 18, 2008
Page 3 

Mr. David H. Brau 

May 4, 2006 

If you have questions concerning this correspondence, or if you require additional information concerning the BART 

process, please contact Ms. Julie Aslinger at (615) 532-0587. 

Sincerely, 

Barry R. Stephens, P.E. 

Director 

Tennessee Division of Air Pollution Control 

cc: Mr. Bruce Davis, Consultant – Air Quality Technology 

Mr. John Finke – Metropolitan Health Department 

 BART File (JA) 

 Green File 

 Certified File 

 BRS 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 410

January 18, 2008
STATE OF TENNESSEE 

DEPARTMENT OF ENVIRONMENT AND CONSERVATION 

DIVISION OF AIR POLLUTION CONTROL 

9th Floor, L & C Annex 

401 Church Street 

Nashville, Tennessee 37243-1531 

CERTIFIED MAIL 7004 0550 0000 9791 4605 

 RETURN RECEIPT REQUESTED 

May 4, 2006 

 

Mr. Stephen Gossett 

Eastman Chemical Company 

200 South Wilcox 

Kingsport, TN 37660 

Reference Number: 82-0003-G1 

Dear Mr. Gossett: 

As you know, the United States Environmental Protection Agency (EPA) published the final Regional Haze 

Regulations and Guidelines for Best Available Retrofit Technology (BART) in the Federal Register on July 6, 2005, 

(70 FR 39104). This final rule requires that the State of Tennessee (“State”) submit a State Implementation Plan 

(“SIP”) for regional haze by December 17, 2007. The SIP must contain emission limitations representing BART 

and schedules for compliance with BART for each BART-eligible source that may reasonably be anticipated to 

cause or contribute to any impairment of visibility in any mandatory Class I Federal area. In order to fulfill the 

SIP requirement, a BART determination must be conducted for each BART-eligible source at your facility. 

Appendix Y to 40 CFR 51 contains guidelines for the BART determination process. 

Step 1. Identification of BART-eligible sources: 

Based on the criteria specified in Appendix Y, the State has identified the BART-eligible sources located at your 

facility. Please contact Julie Aslinger if you have questions regarding which sources at your facility have been 

identified as BART-eligible. 

Step 2. Identification of sources “subject to BART”: 

The State has determined that the sources identified as BART-eligible at your facility are subject to BART. You are 

required to proceed with the BART determination process. However, you are free to pursue your own exemption 

modeling. If you choose to perform your own exemption modeling, you must submit an exemption modeling 

protocol to the State with thirty (30) days of receipt of this letter. 

Step 3. BART determination (Analysis of BART options): 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 411

January 18, 2008
Page 2 

Mr. Stephen Gossett 

May 4, 2006 

The third step of the BART process is the analysis of BART control options. This step requires selection of 

technically feasible, cost effective control technologies and use of the CALPUFF Model to determine the expected 

visibility improvement. Note that Appendix Y contains specifics for determining what types of BART emission 

control options are feasible, if existing emissions controls are adequate for BART, or if no emission controls are 

feasible. See below for BART determination submittal deadlines. 

Step 4. Enforceable limits/compliance date 

The fourth step of the BART process is for the State to establish enforceable emission limits that reflect the BART 

requirements and assure that compliance with these limitations is achieved by the date specified in Appendix Y. The 

current compliance date is specified as no later than five (5) years after approval of Tennessee’s SIP by EPA. 

Following approval of your BART determination, it may be necessary to modify your current Air Pollution Control 

operating permit. 

In order for the State to meet the SIP submittal deadline of December 17, 2007, the following deadlines for required 

submittals have been established: 

June 30, 2006 – Submit site-specific modeling protocol 

Summer 2006 – Conduct BART determination 

November 1, 2006 – Submit BART determination, including CALPUFF modeling results 

VISTAS BART Resources 

VISTAS has been developing several resources that may be useful to BART eligible sources including the 

“VISTAS Protocol for the Application of the CALPUFF Model for Analyses of Best Available Retrofit Technology 

(BART)”, 12 km CALMET (CALMET is a meteorological data processing module associated with the CALPUFF 

model) Data, VISTAS subdomains for refined modeling, 4 km CALMET Data, a VISTAS version of CALPUFF and 

associated documentation, an example application of CALPUFF for BART purposes, and CALMET and CALPUFF 

input files. With the exception of the CALMET data sets, most of these items are available on the BART portion of 

the VISTAS website, located at www.vistas-sesarm.org/BART. To obtain the 4 km or 12 km CALMET data sets 

which are currently available, please contact Julie Aslinger at (615) 532-0587 or Julie.Aslinger@state.tn.us. The 

CALMET data sets are rather large. For data transfer purposes, you will need to provide an appropriate size fire 

wire or USB drive onto which the data will be copied. You must also include a prepaid and addressed postage label 

for shipping the drive back to you. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 412

January 18, 2008
Page 3 

Mr. Stephen Gossett 

May 4, 2006 

If you have questions concerning this correspondence, or if you require additional information concerning the BART 

process, please contact Ms. Julie Aslinger at (615) 532-0587. 

Sincerely, 

Barry R. Stephens, P.E. 

Director 

Tennessee Division of Air Pollution Control 

cc: Johnson City Environmental Field Office 

 82-0003-G1 

 82-0003 BART File (JA) 

 Green File 

 Certified File 

 BRS 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 413

January 18, 2008
STATE OF TENNESSEE 

DEPARTMENT OF ENVIRONMENT AND CONSERVATION 

DIVISION OF AIR POLLUTION CONTROL 

9th Floor, L & C Annex 

401 Church Street 

Nashville, Tennessee 37243-1531 

CERTIFIED MAIL 7004 0550 0000 9791 4612 

 RETURN RECEIPT REQUESTED 

May 4, 2006 

 

Mr. Gordon G. Park 

Manager of Environmental Affairs 

Tennessee Valley Authority 

5D Lookout Place 

1101 Market Street 

Chattanooga, TN 37402-2801 

Reference Numbers: 01-0009-G1 and 81-0011-G1 

Dear Mr. Park: 

As you know, the United States Environmental Protection Agency (EPA) published the final Regional Haze 

Regulations and Guidelines for Best Available Retrofit Technology (BART) in the Federal Register on July 6, 2005, 

(70 FR 39104). This final rule requires that the State of Tennessee (“State”) submit a State Implementation Plan 

(“SIP”) for regional haze by December 17, 2007. The SIP must contain emission limitations representing BART 

and schedules for compliance with BART for each BART-eligible source that may reasonably be anticipated to 

cause or contribute to any impairment of visibility in any mandatory Class I Federal area. In order to fulfill the 

SIP requirement, a BART determination must be conducted for each BART-eligible source at your facility. 

Appendix Y to 40 CFR 51 contains guidelines for the BART determination process. 

Step 1. Identification of BART-eligible sources: 

Based on the criteria specified in Appendix Y, the State has identified the BART-eligible sources located at your 

facility. Please contact Julie Aslinger if you have questions regarding which sources at your facility have been 

identified as BART-eligible. 

Step 2. Identification of sources “subject to BART”: 

The State has determined that the sources identified as BART-eligible at your facility are subject to BART. You are 

required to proceed with the BART determination process. However, you are free to pursue your own exemption 

modeling. If you choose to perform your own exemption modeling, you must submit an exemption modeling 

protocol to the State with thirty (30) days of receipt of this letter. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 414

January 18, 2008
Page 2 

Mr. Gordon G. Park 

May 4, 2006 

Step 3. BART determination (Analysis of BART options): 

The third step of the BART process is the analysis of BART control options. This step requires selection of 

technically feasible, cost effective control technologies and use of the CALPUFF Model to determine the expected 

visibility improvement. Note that Appendix Y contains specifics for determining what types of BART emission 

control options are feasible, if existing emissions controls are adequate for BART, or if no emission controls are 

feasible. See below for BART determination submittal deadlines. 

Step 4. Enforceable limits/compliance date 

The fourth step of the BART process is for the State to establish enforceable emission limits that reflect the BART 

requirements and assure that compliance with these limitations is achieved by the date specified in Appendix Y. The 

current compliance date is specified as no later than five (5) years after approval of Tennessee’s SIP by EPA. 

Following approval of your BART determination, it may be necessary to modify your current Air Pollution Control 

operating permit. 

In order for the State to meet the SIP submittal deadline of December 17, 2007, the following deadlines for required 

submittals have been established: 

June 30, 2006 – Submit site-specific modeling protocol 

Summer 2006 – Conduct BART determination 

November 1, 2006 – Submit BART determination, including CALPUFF modeling results 

VISTAS BART Resources 

VISTAS has been developing several resources that may be useful to BART eligible sources including the 

“VISTAS Protocol for the Application of the CALPUFF Model for Analyses of Best Available Retrofit Technology 

(BART)”, 12 km CALMET (CALMET is a meteorological data processing module associated with the CALPUFF 

model) Data, VISTAS subdomains for refined modeling, 4 km CALMET Data, a VISTAS version of CALPUFF and 

associated documentation, an example application of CALPUFF for BART purposes, and CALMET and CALPUFF 

input files. With the exception of the CALMET data sets, most of these items are available on the BART portion of 

the VISTAS website, located at www.vistas-sesarm.org/BART. To obtain the 4 km or 12 km CALMET data sets 

which are currently available, please contact Julie Aslinger at (615) 532-0587 or Julie.Aslinger@state.tn.us. The 

CALMET data sets are rather large. For data transfer purposes, you will need to provide an appropriate size fire 

wire or USB drive onto which the data will be copied. You must also include a prepaid and addressed postage label 

for shipping the drive back to you. 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 415

January 18, 2008
Page 3 

Mr. Gordon G. Park 

May 4, 2006 

If you have questions concerning this correspondence, or if you require additional information concerning the BART 

process, please contact Ms. Julie Aslinger at (615) 532-0587. 

Sincerely, 

Barry R. Stephens, P.E. 

Director 

Tennessee Division of Air Pollution Control 

cc: Ms. Elizabeth Bailey 

Knoxville Environmental Field Office 

Nashville Environmental Field Office 

 01-0009-G1 

 01-0009 BART File (JA) 

81-0011-G1 

 81-0011 BART File (JA) 

 Green File 

 Certified File 

 BRS 

Pre-Hearing Draft

Regional Haze SIP for TN Class I Areas

Appendix L.8 - 416

January 18, 2008