## Proposed BART Determination fo r 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)

### 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) re vision 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 Operatio ns (TNO) facility in Kingsport, Tennessee as a BART-eligible source. Based on the Q/D (ton s 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 require d Case-by-Case BART Analysis. Accordingly, the purpose of this document is to present East man'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 Effectiven ess 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-elig ible 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 Associati on (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 de fined 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, 2007Table 1Eastman TNO BART-eligible Emission UnitsNOxSO22005 Actual Emissions2005 Actual EmissionsMSOPPESVent IDEmission UnitDescriptionTonsBasisAllowableExistingControlsTonsBasisAllowableExistingControlsCoal-fired industrial boilers02B-253-1A-EBoilers #25 -#29(pulverized coal,tangentially fired, 655MBtu/hr each)4,555CEMSN/ALNB(ozoneseason)14,309CEMS2.4lb/MBtuSulfur content02B-83-1CBoiler 24 (overfeedstoker, 500 MBtu/hr)569CEMSN/ANone1,494FuelUsage,SulfurContent2.4lb/MBtuSulfur contentCracking Furnaces (Natural Gas-Fired)16B-6C-1AFurnace 27 (18MBtu/hr)6.5AP-42,FuelUsage10.6 tpyNone0.16AP-42,FuelUsage0.5 tpySulfur content16B-6C-1BFurnace 28 (18MBtu/hr)6.5AP-42,FuelUsage10.6 tpyNone0.16AP-42,FuelUsage0.5 tpySulfur contentOthers25OCBATCHVarious(seeTitle Vapplication)General Purpose BatchChemicalManufacturing14.0tpyScrubbers7.2tpyScrubbersEastman BART SubmittalPage 2 of 34February 27, 2007

### 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 Co mbustion 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 pr ecipitators are located at ground level. These precipitators were inst alled in the early 1990s.

Existing NOx Controls: During 2001-2003, the burners on these boilers wereretrofitted 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 modi fied coal tips that provide for flame

attachment closer to the bu rners. 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, ther e are no existing controls of sulfur dioxide emissions. The average emissi on rate for calendar year 2005 was 1.4

lb/MBtu.

Eastman BART Submittal Page 3 of 34 February 27, 20073.1.2 Step 1: Identify Available Retrofit Emission Control Techniques :

Particulate matter: These boilers are equipped with highly efficient electrostatic precipitators (ESPs) fo r control of particulate matter emissions. The Title V permit requires periodic performance test s. The results of the most recent

tests and the estimate of actual emissi ons 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 Indust rial Boiler Maximum Achievable Control Technology (MACT) standard for industrial boilers (40 CFR 63 Subpart DDDDD). This rule sets a PM emissi on 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 co st 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 recen t (September 13, 2004) and no new proven technologies have emerged since this recent date. 3. It is obvious by engineering judgemen t that the cost to replace the existingESPs 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, 2007Nitrogen 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 pulver ized coal boilers (#25-#29). Note, technologies that achieve lower c ontrol 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 infeasibleis 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. Th ese steam load swings are accompanied by significant flue gas temperature ch anges. 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, 2007because of the load-following nature of industrial boile rs, 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 on e 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 clarif iers (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 Co ntrol Effectiveness of Rema ining Control Technologies

Eastman determined control effectiveness of the available t echnologies 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, 2007Table 6 - B-253

SO2 Available Retrofit Technolo gies – 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 Im pacts 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 type s 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, wh ile these capital cost estimates are in 2006 dollars, construction costs for industrial projects of this nature involving heavy use of steel, stainless steel, an d 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, 2007power 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 Attach ment 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, li mestone, and caustic. Annual maintenance costs are assumed at three percent of capita l. 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 parame ters 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 discusse d in Part 3 (Non-air Quality Impacts) and in Section

Eastman BART Submittal Page 8 of 34 February 27, 20074 (Visibility Impacts), Eastman questions that this technology should be employed outside of the ozone season.

EPA's BART guidance establishes a pres umptive 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. Neve rtheless, Eastman evaluated the use of SOFA technologies to achieve this presumptive level, but our analysis has concluded that probable detrimental e ffects to the opera tion and mechanical integrity of the boiler are likely. Chief among these technical concerns is further starving the lower portions of the fu rnace of combustion air and subsequent increases in LOI. Any further increas e 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 bo ilers as compared to large u tility units, residence time in the furnace is reduced giving less time for complete combustion of the coal. It is therefore not technically correct to ex trapolate NOx reduction results commonly obtained in utility boilers to the small furnaces at B-253. Therefore, while Eastman has evaluated the potential cost-e ffectiveness 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 si de of the range includes the cost of a booster fan and larger ductwork. This larg e 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 boos ted SOFA system. Detailed and costly computational fluid dynamics modeling would be required to determine which of these systems would be required to m eet the presumptive li mit. 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 a ll 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 obta in good mixing in the furnace in order to obtain the expected removal efficienci es, and so SNCR would have the same

drawbacks as SOFA as noted above.

Eastman BART Submittal Page 9 of 34 February 27, 2007Sulfur 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 Effectiv eness 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 footpr int either eliminates it as an option or drives up cost considerably to relocate buildings, railroad tr acks, ash ponds, etc. Also, its use has been extremely limited and Eastman' s confidence that it can be su ccessfully 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 regiona lly 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. Eastma n'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 s ubstantially 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 February 27, 2007footprint 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 spra y 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 conditiona l 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 incremen tal 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 qualit y 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 landf ill. 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, 2007resulting in consumption of additional ener gy (natural gas) and raw materials to produce the cement along with the associ ated 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 leachat e collection systems and should have no impact on groundwater. Any leachate or stormw ater 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 wate r 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. Theref ore, 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 qu ality 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

### 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 Treat ment 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-fiel d 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, respectivel y, 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, ther e are no existing controls of sulfur dioxide emissions. The average emissi on rate for calendar year 2005 was 1.4

lb/MBtu.

Eastman BART Submittal Page 13 of 34 February 27, 20073.2.2 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 emissi ons 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 judgemen t that the cost to replace the existingESPs 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 A vailable 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, 2007Sulfur Dioxide

Eastman has identified the technologies listed below in Table 11 as available retrofit technologies for its Boiler 24:

Table 11 – Boiler 24 SO2 Ava ilable 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 tech nically 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 Indu strial 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 increas es the risk and uncertainty that technologies such as FGR and OFA mi ght 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 temperat ure 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, 2007injected. It would not be possible to completely rearrange the burner configurations to acco mmodate 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 respondi ng 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 perform ance. 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 inject ion discussed for SNCR apply also to SCR. Additionally, du e to space considerations, there is no space for a SCR reactor. A hybrid SNCR/S CR system combines SNCR with a smaller in-duct catalyst section do wnstream of the economizer and upstream of the air preheater. East man 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 perf orming SO2 control technologies such as SDA, Eastman has investigated the t echnical feasibility of lower cost/lower performing technologies such as sorbent in jection, 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 ach ieve 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 le d 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 mu ch 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, 2007has 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 injec tion using lime injected near the top of the boiler in the region of the superh eater was examined. Injecting the reagent in the higher temperature zone (as opposed to the ductwork downstream of the air preheater) prov ides 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 coincide s with the area where we currently inject liquid chemical wastes and bios ludge for destruction. Trying to inject limestone in this region could jeopardize both those operations. The second concern is the impact th e lime injection would have on all downstream components including su perheater tubes, economizer, and air preheaters. Given that the Eastman facility is highly dependent on Boiler 24 not only for steam and elect ricity, but also for disposal of liquid chemical wastes and wastewat er 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, bu t any additional ash loading from upstream SO2 removal devices could not be handled by the existing precipitator without m odifications or replacement. This can be shown by looking at the Sp ecific 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 preci pitator technology:

"Precipitator size also is relate d 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 norm ally 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 acf m. 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, 2007normal 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 Co ntrol Effectiveness of Rema ining Control Technologies

Eastman determined control effectiveness of the available t echnologies 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 Technolo gies – 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 achiev e 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 Im pacts 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 type s 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, wh ile these capital cost estimates are in 2006 dollars, construction costs for industrial projects of this nature involving heavy use of steel, stainless steel, an d 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, 2007Projected annual operating and maintenance costs are shown in Attachment 2.

The unit costs assumed are shown in Attach ment 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, li mestone, 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 parame ters 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, 2007Table 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 Fede ral Register, this standard recognizes the technical difficulties of facilities firing in herently low sulfur fuels such as the Eastern bituminous coals Eastman utilizes from Eastern Kentucky and Southwest Virginia coal mines.

Our evaluation of the technologies availabl e 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. Th erefore, there is no economy of scalewith 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 sh utdown 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 th is boiler. FGD technologies are muchmore cost-effective for the high sulfur coal in the Midwest and on larger utilitytype boilers.

Based on this evaluation, Eastman conclu des there is no technically feasible

alternative that is reasonab ly 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 qualit y 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 dispos ed at TNO's on-site nonhazardous waste

landfill. We have estimated this add itional waste would shorten the landfill life

Eastman BART Submittal Page 20 of 34 February 27, 2007by about one year. The loss of landfill space should not cause a direct environmental impact as the landfill ha s 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 wate r 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 sour ces. 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

### 3.2 Building 6C Cracking Furnaces #27 and #28

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

acetic acid that occurs inside the tube asse mblies 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 PE S 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 inte gral to the process and considered not BARTeligible.

The furnaces were built in 1977 by Heat Research Corpor ation 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 si de of the two rows of burner

boxes.

Given the low NOx emi ssion potential from these small furn aces (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 im portant 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 So urce 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 th ese furnaces under the BART rule.

Eastman BART Submittal Page 22 of 34 February 27, 2007

### 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 thr ee commenced operation du ring 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 pe r 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, 2007Table 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 (SO 2 

### ) Emission Limits Table

ID Emission Unit PES Attachment and

Vent I.D. PM

in pounds

per hour PM

in tons during

time

T* SO 2 in pounds per hour SO 2 in tons during

time

T*

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

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

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

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

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

f Cyclic Intermediates & Dye Cakes E quipment 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 th e 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 co ntrol efficiencies from 20-60 percent and are

limited to annual emissions of 22.4 tons. Clea rly, 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

### 4.0 Visibility Impact s 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 98 th percentile) day in the year. The third is the summation of the change in deciview ca used 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. East man 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

8 th 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 imp act was less than 0.5 dv. In these cases, to be conservative, the number of days above 0.5 dv pred icted 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, 2007Table 16 Calpuff ScenariosModeled Emission RatesDescription253 SO2g/sec24 SO2g/sec253 NonozoneNoxg/sec253OzoneNoxg/sec24 Noxg/secTotalSO2g/secTotalNonozoneseasonNoxg/secTotalOzoneSeasonNox g/secBaselineBoilers 24-297667724713529842276163Scenario 1SDA/ESP at B-2532227724713529299276163Scenario 2SDA/FF at B-253617724713529138276163Scenario 3Wet FGD at B-253387724713529115276163Scenario 4Wet FGD at B-253 + Wet FGD at Blr 243842471352942276163Scenario 5Scenario 3 + LNB Year-round at B-253387715813529115187163Scenario 6Scenario 5 + SOFA at B-253387712710829115155136Scenario 7Scenario 6 + SNCR at B-25338777058291159887Baseline Blr 24Only0 77 0 0 29 77 29 29Baseline B-6C+ OCBatch0.000.000.000.000.000.791.161.16Note: The Modeling Protocol (see Attachment 1) shows the maximum daily emissions assumed for the baseline conditions. Only SO2 and NOx are shown here sincethose are the only visibility-impairing pollutants that are considered for emission reductions from BART for TNO's BART-eligible sources.Eastman BART SubmittalPage 26 of 34February 27, 2007Table 17 – Visibility Impacts AnalysisBaseline (Boilers 24-29)200120022003DailyDailyDailyDailyDailyDaily# daysSum8th High# daysSum8th High# daysSum8th High>0.5/1.0dvdelta dvyrdelta dv>0.5/1.0dvdelta dv-yrdelta dv>0.5/1.0dvdeltadv-yrdelta dvLinville Gorge, NC80/38114.21.6656/19100.12.0680/41120.11.81GreatSmoky Mtns, TN72/47125.42.2854/2798.02.3049/3798.22.55Shining Rock, NC52/3078.31.4433/952.61.2234/1452.81.33Joyce Kilmer, NC34/1456.81.3421/1045.31.2629/1549.81.67Cohutta, GA16/636.20.9016/427.50.8116/827.81.01James River Face, VA17/140.30.649/131.80.5320/549.50.79Total451.2355.2398.1Avg401.5GRSMAvg2.38Scenario 1 (253 SDA/ESP)200120022003DailyDailyDailyDailyDailyDaily# daysSum8th High# daysSum8th High# daysSum8th High>0.5/1.0dvdelta dvyrdelta dv>0.5/1.0dvdelta dv-yrdelta dv>0.5/1.0dvdeltadv-yrdelta dvLinville Gorge, NC38/358.50.8929/852.21.0346/963.31.10GreatSmoky Mtns, TN50/2166.91.4234/1753.91.1436/1550.81.36Shining Rock, NC20/436.00.6510/326.20.5812/024.10.54Joyce Kilmer, NC10/427.20.658/221.10.5010/422.80.79Cohutta, GA7/016.70.394/011.90.326/011.80.41James River Face, VA2/019.70.321/016.00.294/124.20.38Total225.0181.3197.0Avg201.1GRSMAvg1.31Eastman BART SubmittalPage 27 of 34February 27, 2007Table 17 – Visibility Impacts AnalysisScenario 2 (253 SDA/FF)200120022003DailyDailyDailyDailyDailyDaily# daysSum8th High# daysSum8th High# daysSum8th High>0.5/1.0dvdelta dvyrdelta dv>0.5/1.0dvdelta dv-yrdelta dv>0.5/1.0dvdeltadv-yrdelta dvLinville Gorge, NC8/041.40.7012/437.30.7419/446.04,87GreatSmoky Mtns, TN31/747.80.9921/638.60.9417/635.270.91Shining Rock, NC9/123.30.545/118.00.392/015.50.38Joyce Kilmer, NC7/118.10.473/013.10.356/014.320.44Cohutta, GA6/011.00.291/07.00.181/06.880.21James River Face, VA1/013.40.211/011.70.252/116.710.29Total155.0125.6134.7Avg138.4GRSMAvg0.95Scenario 3 (253 Wet FGD)200120022003DailyDailyDailyDailyDailyDaily# daysSum8th High# daysSum8th High# daysSum8th High>0.5/1.0dvdelta dvyrdelta dv>0.5/1.0dvdelta dv-yrdelta dv>0.5/1.0dvdeltadv-yrdelta dvLinville Gorge, NC11/039.00.6011/435.10.7218/443.530.85GreatSmoky Mtns, TN28/645.10.9723/636.30.9121/6330.89Shining Rock, NC9/121.50.535/116.80.371/012.470.36Joyce Kilmer, NC6/016.70.453/012.00.315/012.980.37Cohutta, GA5/010.10.281/06.30.161/06.180.18James River Face, VA1/012.50.200/011.00.242/115.620.25Total144.9117.5123.8Avg128.7GRSMAvg0.92Eastman BART SubmittalPage 28 of 34February 27, 2007Table 17 – Visibility Impacts AnalysisScenario 4 (Scenario 3 + Boiler 24 Wet FGD)200120022003DailyDailyDailyDailyDailyDaily# daysSum8th High# daysSum8th High# daysSum8th High>0.5/1.0dvdelta dvyrdelta dv>0.5/1.0dvdelta dv-yrdelta dv>0.5/1.0dvdeltadv-yrdelta dvLinville Gorge, NC8/031.00.539/324.50.6414/335.340.65GreatSmoky Mtns, TN19/537.30.8716/330.10.8413/526.810.84Shining Rock, NC3/015.60.454/113.00.340/010.360.29Joyce Kilmer, NC5/012.60.373/08.60.232/09.270.27Cohutta, GA1/07.40.231/04.10.110/03.930.12James River Face, VA1/09.60.160/08.90.221/012.070.24Total113.489.297.8Avg100.1GRSMAvg0.85Scenario 5 (Scenario 3 + LNB Year-round at B-253)200120022003DailyDailyDailyDailyDailyDaily# daysSum8th High# daysSum8th High# daysSum8th High>0.5/1.0dvdelta dvyrdelta dv>0.5/1.0dvdelta dv-yrdelta dv>0.5/1.0dvdeltadv-yrdelta dvLinville Gorge, NC8/033.60.548/129.30.5413/137.430.67GreatSmoky Mtns, TN20/538.80.7515/230.50.7412/329.340.79Shining Rock, NC4/019.00.383/114.20.310/012.570.32Joyce Kilmer, NC6/014.40.362/010.60.284/011.490.36Cohutta, GA1/08.70.230/05.70.160/05.660.18James River Face, VA1/010.70.180/09.00.191/013.150.23Total125.199.2109.6Avg111.3GRSMAvg0.76Eastman BART SubmittalPage 29 of 34February 27, 2007Table 17 – Visibility Impacts AnalysisScenario 6 (Scenario 5 + SOFA at B-253)200120022003DailyDailyDailyDailyDailyDaily# daysSum8th High# daysSum8th High# daysSum8th High>0.5/1.0dvdelta dvyrdelta dv>0.5/1.0dvdelta dv-yrdelta dv>0.5/1.0dvdeltadv-yrdelta dvLinville Gorge, NC6/031.10.507/027.00.4910/034.460.57GreatSmoky Mtns, TN17/235.70.6714/227.90.6511/325.990.71Shining Rock, NC4/017.80.343/113.10.300/011.760.29Joyce Kilmer, NC4/013.410.322/09.940.254/010.78.36Cohutta, GA1/08.10.210/05.40.150/05.40.18James River Face, VA0/09.80.160/08.20.171/012.110.20Total115.981.6100.5Avg99.3GRSMAvg0.68Scenario 7 (Scenario 6 + SNCR at B-253)200120022003DailyDailyDailyDailyDailyDaily# daysSum8th High# daysSum8th High# daysSum8th High>0.5/1.0dvdelta dvyrdelta dv>0.5/1.0dvdelta dv-yrdelta dv>0.5/1.0dvdeltadv-yrdelta dvLinville Gorge, NC3/026.50.405/022.90.416/029.060.49GreatSmoky Mtns, TN10/029.90.598/023.20.539/121.730.55Shining Rock, NC3/015.60.282/111.20.250/010.290.25Joyce Kilmer, NC2/011.60.260/07.80.222/09.50.35Cohutta, GA0/07.10.180/04.90.140/04.960.17James River Face, VA0/08.40.130/06.90.131/010.270.17Total99.276.885.8Avg87.3GRSMAvg0.56Eastman BART SubmittalPage 30 of 34February 27, 2007Table 17 – Visibility Impacts AnalysisBaseline (Boiler 24 Only)200120022003DailyDailyDailyDailyDailyDaily# daysSum8th High# daysSum8th High# daysSum8th High>0.5/1.0dvdelta dvyrdelta dv>0.5/1.0dvdelta dv-yrdelta dv>0.5/1.0dvdeltadv-yrdelta dvLinville Gorge, NC0/012.50.170/010.80.211/013.60.21GreatSmoky Mtns, TN0/013.10.230/010.10.230/09.70.24Shining Rock, NC0/08.10.151/05.40.120/05.20.13Joyce Kilmer, NC0/05.80.150/04.40.130/04.90.18Cohutta, GA0/03.70.090/02.70.070/00.10.13James River Face, VA0/04.20.070/03.40.050/05.10.07Total47.336.838.7Avg40.9GRSMAvg0.23Baseline (B-6C Furnaces and OC-Batch)200120022003DailyDailyDailyDailyDailyDaily# daysSum8th High# daysSum8th High# daysSum8th High>0.5/1.0dvdelta dvyrdelta dv>0.5/1.0dvdelta dv-yrdelta dv>0.5/1.0dvdeltadv-yrdelta dvLinville Gorge, NC0/00.20.000/00.10.000/00.20.00GreatSmoky Mtns, TN0/00.20.010/00.20.010/00.20.01Shining Rock, NC0/00.10.000/00.10.000/00.10.00Joyce Kilmer, NC0/00.10.000/00.10.000/00.10.00Cohutta, GA0/00.00.000/00.00.000/00.00.00James River Face, VA0/00.00.000/00.00.000/00.10.00Total0.60.60.6Avg0.6GRSMAvg0.01Eastman BART SubmittalPage 31 of 34February 27, 2007Eastman 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 98 th 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-effectiv e in terms of visibility improvement in Class I Areas. These are (1) spray dryer absorbers with fa bric filters and (2) sodi um hydroxide (caustic)

scrubbers. Either of these te chnologies 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 recepto r in each Class I Area on each day in the three year period). The baseline ca se also shows an average 8 th 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 emissi on 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)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 8 th daily maximum (at the worst recepto r 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 sma ller 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 technologi es as BART. The risk to boiler reliability is discussed above in Section 3.1.5. The non-air qua lity impacts are discussed in Section 3, Part 3. These include loss of flyash sales to the conc rete industry offsetting cement manufacturing, increased landfill rates, and loss of boiler effici ency 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 - $545,917Eastman 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 98 th 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 st ated 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 revise d to establish an enforceable emission limit to reflect the BART requiremen ts. 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 ap plied 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 serv e the TNO manufacturing facility.

# Attachment 1

Capital Cost Estimates

# 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 cell s

Purchased Equipment Cost 1,750,000 $

Eastman Provided Equipmen t

- $

Equipment Installation Facto r 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

# 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 cell s

V endor Purchased Equipment Cost 548,000 $

Eastman Provided Equipmen t

- $

Equipment Installation Facto r 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 $

## Conceptual Capital Cost Estimate

Project: BOILER 24 SDA WITH FABRIC FILTER ESTIMATE

Date: Thursday, January 04, 2007 Site: Kingsport

V endor 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 $

# Attachment 2

Annual Operating and Maintenance CostsTechnologyAdditionalOperatorsAddedElectricLoadAddedElectricalPower CostReagent &Water CostMaint. CostAsh SaleLostAdditionalAshDisposalAdditionalWWTCostLOIChangeLOI CostAdditionalBIF MACTTestingCostsTotal AnnualCost (O/M)$/yrhp$/yr$/yr$/yr%$/yr$/yr%$/yr$/yr$/yrB-253 Nox OptionsLow-Nox Mode Year 'Round$00$0$0$0100$120,540$025$209,475$0$330,015SOFA (non-boosted)$00$0$0$114,00025$30,135$00$0$0$144,135SOFA (boosted)$0875$226,910$0$480,00025$30,135$05$41,895$0$778,940SOFA (non-boosted)+SNCR$0315$81,687$4,981,538$240,000100$120,540$00$0$0$5,423,766SOFA (boosted) + SNCR$0900$233,393$5,329,602$645,000100$120,540$05$41,895$0$6,370,430SCR$01,250$324,157$7,089,506$2,850,000100$120,540$00$0$0$10,384,202Natural Gas Reburn$00$0$27,687,322$441,8250$0$00$0$0$28,129,147B-253 SO2 OptionsDry FGD with ESP$300,0002,692$698,197$2,251,336$2,550,000100$283,895$00$0$0$6,083,428Dry FGD + FF Retrofit$300,0005,050$1,309,593$2,192,564$3,750,000100$359,613$00$0$0$7,911,770LSFO$300,0005,047$1,308,863$999,022$4,800,0000$317,856$2,8480$0$0$7,728,589Caustic Scrubber$300,0002,610$676,839$4,840,113$2,280,0000$0$45,2020$0$0$8,142,154Dual Alkali$300,0002,825$732,594$2,504,936$3,060,0000$317,856$219,8160$0$0$7,135,202Boiler 24 SO2 OptionsSDA + FF$0525$136,146$563,579$1,200,0000$16,797$00$0$0$1,916,522Caustic Scrubber$0285$73,908$653,142$780,0000$0$1,8080$0$0$1,507,050

# Attachment 3

Unit Cost

## 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

# Attachment 4

Design Parameters

### Attachment 4 Design Parameters

Reagent Stoichiometric Ratio Gas Volume (acfm) Flue Gas Temperature (deg F) Pressure Drop (inches water) A mmonia 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

# Attachment 5

Modeling Protocol

(Included in Attachment L.6)

## BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

TVA CUMBERLAND FOSSIL PLANT

July 17, 2007

## CONTENTS

Section Page

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

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

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

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

ii

## I. Introduction

Guidelines for Best Available Retrofit Tec hnology (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 anti cipated 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 pe r 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 subj ect to BART, determina tion 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 e xpected from the application of controls

The TVA Cumberland Fossil Plant (CUF), located in Stewart County, TN, has two pulverized-coal-fired steam generators that ar e considered BART eligible. Units 1 and 2 are nominally rated at about 1325 MW each. Both units are equipped with flue gas desulfurization (FGD) systems for sulfur dioxide (SO 2 

### ) control, selective catalytic reduction systems for contro lling nitrogen oxides (NO

x 

### ), and electrostatic precipitators (ESPs) to control particulate matter (PM) em issions. In addition, CUF currently uses hydrated lime injection on both uni ts 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 Depart ment of Environment and Conservation (TDEC), compliance with CAIR sa tisfies BART requirements for SO 2 

### and NO

x 

### emissions at electric generating units. As a result, this BART analysis only considers

PM 10 

### 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

### 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 m odeling showed that two units at CUF are subject to BART requirements for PM 10 

### . 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 aff ected Class I areas can be attributed to

condensable PM 10 

### emissions (i.e., SO 3 

### ). So the engineering evaluation for CUF focuses

on control of SO 3 

### /H 2 

### SO 4 

### emissions.

2

## II. BART Engineering Analysis

Emissions

Based on emissions testing at TVA facili ties using hydrated lime injection, stack emission levels of about 7 ppmdv SO 3 

### (both corrected to 3%0 2 

### ) can be achieved. This

value was used as the baseline fo r the engineering analysis.

One option was identified as technically feasible for controlling additional SO 3 

### emissions

at CUF--a wet ESP . An ESP controls PM by imparting a negative charge to fly ash particles entering the device and collecting th em on positively charged plates. In a wet ESP, the fly ash is removed by flushing the co llection plates with water. Wet ESPs are very expensive, requiring large capital invest ments. They also require large volumes of water for cleaning the plates. This te chnology is capable of achieving an SO 3 

### emission level of approximately 2 ppmdv.

Based on actual fuel usage rates for CUF Units 1 and 2 in 2005, baseline annual

emissions of SO 3 

### (expressed as H 2 

### SO 4 

### ) 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, Paradi se 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 co sts 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 a bout $176 million per unit. Total annual costs are about $50.5 million per year. The corr esponding 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 fromconsideration as a basis for BART.

Non-air Environmental Impacts

As stated previously, a wet ESP is a wa ter 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.

3

### 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

.



### 4

### 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 ft 2 /1000 cfm, 4.5 million cfm

Material $ 787,610 1% of PEC

Utilities

Electricity-fan $ 599,342 2" H 2 O Δ p, $0.06/kWhElectricityoperating $ 330,830 capacity factor (CF)=0.7

Water $ 1,655,640 5 gal/min per 1000 cfm, $0.2/1000 gal, CF=0.7
Waste Disposal $ 16,556,400 $2/1000 gal

Total DC $ 20,047,613

Indirect Annual Costs (IC)

Overhead $ 543,241 60% of operating labor and materials Administrative charge $ 3,528,493 2% of TCI Payment in lieu of

taxes $ 1,764,246 1% of TCI

Insurance $ 1,002,169 1% of TCI Capital recovery $ 23,619,516 CRF = 0.1339

Total IC $ 30,457,664

Total Annual Cost $ 50,505,277

*Based on information from the EPA Air Pollution Control Cost Manual, Sixth Ed . Capital recovery factor (CRF) based on 12% interest rate and 20-yr equipment life.



### 5

## III. BART Modeling Analysis

TVA conducted BART modeling for CUF follo wing 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 th e 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 mode ling 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 we re calculated is provided in that file. All CALPUFF control files, output files and oz one 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 SO 3 

### was entered as H 2 

### SO 4 

### in g/s as

indicated on the “BART” worksheet of the emissions spreadsheet
“CUF_CY06_BART_rev3.xls.” All em issions for the modeling an alysis were calculated assuming operation at maximum heat input to conservatively represent maximum 24-

hour actual emissions. Emissions of HNO 3 

### and PM-NO 3 

### were set to zero, because no

credible emissions factors were available for these species for EGUs. Support for setting

HNO 3 

### and PM-NO 3 

### to zero was found in some SM OKE emissions fa ctors provided by

VISTAS. In the SMOKE emissions table provided by VISTAS, the factor provided for

PM-NO 3 

### was zero, as shown in Table 4. The SM OKE emissions factors were not used except as justification for setting emissions of HNO 3 

### and NO 3 

### 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 ( o 

### K) 321 321

6

### The following steps were used for CALPUF F 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” we re 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 cl ass I area and each year using the output from step 4. Method 6 was used. CALP OST was run separately for each class I area using the output from step 5. Met hod 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-Sp ecific 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 98 th 

### percentile (8 th 

### highest value) for each individual year. The data from the 3 years were combined t ogether and sorted by delta DV to find the

98 th 

### percentile value (22 nd 

### highest value) for the thr ee years combined together.

Table 5. Emission Rates for CUF 1 a nd 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



### 7

### 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 modeli ng 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 detail ed information for the Class I areas that are within 300 km of CUF, including the date a nd receptor where the delta dv was at or

above the 98 th 

### percent contribu tion, is provided in Table 7. The 98 th 

### percent contribution

is used in the 4-km simulations. The 98 th 

### percentile is defined as the 8 th 

### largest value for each individual year or the 22 nd 

### largest value for all 3 years together, whichever is most

conservative.

T able 6. Summary of CALPUFF Resu lts for CUF on 4-km Grid.

Class I Area Dist (km)

from

source

to

nearest receptor # Days with 98 th



### Percent > 0.5 dv,

98 th 

### percentile,

in Class I Area (2001) # Days with 98 th



### Percent > 0.5 dv,

98 th 

### percentile,

in Class I Area (2002) # Days with 98 th



### Percent > 0.5 dv,

98 th 

### percentile,

in Class I Area (2003) # Days with 98 th



### Percent > 0.5 dv,

98 th 

### 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

8

### 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

9

### 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, determ ination modeling conducted for Unit 2 was considered applicable to bot h units. Determination modelin g 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.

10

### T able 8. Summary of CALPUFF Results p er Unit for Baseline on 4-km Grid.

T able 9. Summary of CALPUFF Results p er Unit for Wet ESP on 4-km Grid. Class I Area Dist (km)

from

source

to

nearest receptor # Days with 98 th



### Percent > 0.5 dv,

98 th 

### percentile,

in Class I Area (2001) # Days with 98 th



### Percent > 0.5 dv,

98 th 

### percentile,

in Class I Area (2002) # Days with 98 th



### Percent > 0.5 dv,

98 th 

### percentile,

in Class I Area (2003) # Days with 98 th



### Percent > 0.5 dv,

98 th 

### 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 98 th



### Percent > 0.5 dv,

98 th 

### percentile,

in Class I Area (2001) # Days with 98 th



### Percent > 0.5 dv,

98 th 

### percentile,

in Class I Area (2002) # Days with 98 th



### Percent > 0.5 dv,

98 th 

### percentile,

in Class I Area (2003) # Days with 98 th



### Percent > 0.5 dv,

98 th 

### 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

11

### Table 10. 98th-percentile Baseline Re sults 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



### 12

### 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



### 13

### For each unit, a wet ESP is predicted to reduc e 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 assura nce procedures were practiced by TVA in conducting BART modeling for CUF.

A comparison was made between the switch se ttings 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 protoc ol 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 nece ssary to conduct BART modeling; (2) the change in switch settings would not affect the simulation, or (3) the change was necessary because of refine ments to CALPUFF since Appendix B was published. Examples of (1) include NSPE C and NSE, the number of species and the number of emitted species. The values give n in Appendix B were too low for VISTAS BART modeling. Another example is BC KNH3, 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 IM ESG, a variable that determines whether status messages will be sent to the screen. Examples of change type (3) are SVMIN and SWMIN. Because of re finements to CALPUFF, 12 values were

needed for each of these arra ys instead of the 6 values sp ecified 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 assu re that the procedures worked properly.

Two modelers independently converted th e coordinates for TVA’s BART-eligible facilities and the Class I receptors from la titude/longitude to lambert conformal conic using the COORDS facility in CALPUFF. A third person calculat ed the conversion for the TVA BART-eligible facilities by a co mpletely independent method that did not involve the use of CALPUFF. Comparison of these results ensure d that the conversion was conducted correctly. (The values calcu lated 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). Calcul ated 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 de termine whether the Cla ss 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 provid ed by TRC Environmental. In addition,

14

### maps of the land use, terrain, sources, recep tors and ozone stations were viewed in

CALVIEW to ensure that th ey looked reasonable.

Two calculations were added to the PM-distribut ion 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 a ll Class I areas locate d within 300 km were included. Subsets of these receptors were desi gnated 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, th e results for the three years were imported into a Microsoft ® Excel spreadsheet and sorted to determine the days with the highest delta dv impacts.

15

## IV. Conclusion

Application of a wet ESP would reduce visibi lity 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.

16

### 4APT-APB

Mr. Barry R. Stephens, P.E. Director

Tennessee Division of Air Pollution Control

9 th 

### 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 th e Alcoa, Inc.-Tennessee Operations dated May 18, 2007.

Enclosed are our comments on the Alcoa In c. document. Enclosure 1 describes our comments on the control and cost analys es. Enclosure 2 details our comments on the modeling analysis.

We appreciate your transmittal of this pack age for our consideration. If you have questions regarding this lett er, please contact Jimmy Hou of the Region 4 staff at (404)

562-8965.

Sincerely,

Kay T. Prince

Chief Air Planning Branch

Enclosures

### 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%.

2

### 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 para meters (e.g., emission rates, stack parameters) are correct. EPA Region 4 recommends th at the State carefully compares these parameters with existing permits, databases, et c. 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 whethe r a BART-eligible source can reasonably be anticipated to cause or contri bute to visibility impairment must be documented in the State Implementation Plan (SIP), as must th e 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 Or ganizations 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 a nd 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-e ligible based on dates and later determined otherwise, that reason shoul d also be presented.

Specific Modeling Comments

1. Section 3.1, page 3-4:

a. The submittal states that Potlines 1 a nd 2 and the anode bake furnace are already equipped with sophisticated emission c ontrol equipment for PM, so the BART

determination for these emission units fo cuses primarily on potential reductions

for SO 2 

### and NO X 

### . 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 th e 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 exis ting permits contain conditions to ensure that the baghouses are properly operated and maintained? Since the emissions from these units are claimed to be insigni ficant, it important to assure that the emissions controls are operated properly.

32. 

### CALPOST Method 8

a. 

### Light extinction was calculated in a ve rsion of the CALPOST postprocessor that utilizes the new IMPROVE equation us ing a new method called Method 8. The submittal states that Method 8 provide s 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 ha s not been sufficiently and clearly demonstrated that the new CALPOST provi des 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 CALP UFF to develop visibility impacts was

not discussed.

c. 

### It is incumbent upon the state and the facili ty 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 rela tive humidity at 98 percent by default but the user can change it. EPA guidan ce 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 2 000 Flag report, EPA f(RH) curve or IWAQM 1998 f(RH). If somethin g other than that recommended in the VISTAS modeling protocol was us ed, 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 m odified CALPOST processor is not a generic model that EPA Region 4 recogni zes to be a part of the CALPUFF modeling system. Its use should be justif ied on a case-by-case basis. A detailed justification which addre sses 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.

4

### h. Nitrogen dioxide concentrations: The re port does not discuss the origin of the

NO 2 

### data used in CALPOST. EPA Regi on 4 has determined that it would be acceptable to use the total NO

x 

### concentration as a surrogate for NO 2 

### (i.e., conservatively assume that all NO

x 

### is NO 2 

### ). The total NO

x 

### concentration can easily be obtained when running CALPOS T by turning on the switch to produce

NO

x 

### 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 faci lity. 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 presen ts the CALPUFF modeling results for two

control scenarios. Control S cenario 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 rea lly 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 re presents the current operation.

Appendix B of the Submittal

1. Page 4-11: The first sentence on this pa ge states that “each source is modeled by (the?) group of the same emission rates a nd their source contribu tions 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.

5

### 3. Tables 5-1 through 5-12 should be cons istent in how the modeling results are presented. All of the top ei ght delta visibility impact s should be presented for Linville Gorge, Shining Rock and Cohutta.

4. The state should determine in the Regiona l haze SIP why the 0.5 visibility threshold was applicable for the BART exemption m odeling. 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.

6

### Attachment A

Excerpt from August 24, 2006 Q&A Document

4. How should a State document in the SIP th at 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 cont rols 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 requirem ents 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) mu st begin to comply with the BART limit. Because the BART requirements ar e ‘‘applicable’’ requirements of the CAA, they must be included as titl e 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 i ssuance. This may require that States provide commitments in the SIPs to en sure 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, mu st be addressed to ensure the BART controls are adopted in to the State’s SIP. These elem ents are discussed in detail

with other circumstances in 40 CF R Part 51, Appendix Y – Section V.

• Name of source facility and the specific emission units and pollutants being controlled. (40 CF R 51.308(e)(1)(i) & (ii)).

• Specifics of the controls, control e fficiency(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 maintaine d. (40 CFR 51.308(e)(v))

• Reporting, monitoring, and recordkeep ing 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).

7

### ATTACHMENT B

U.S. EPA Region 4 Review of the VIST AS Methodology for Implementing the New IMPROVE Equation with CALPUFF for BART Modeling

The original Interagency Monitoring of Pr otected 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 co mpound 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 sa lt, which is important at sites near the ocean coasts. As a result of these limitations, the IM PROVE Steering Committee commissioned the development of a new IMPROVE algorithm, wh ich 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 ne eded to process the mass concentrations from CALPOST using the new IMPROVE equati on so that the Best Available Retrofit Technology (BART) analyses could consider bo th 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/CALPOS T data to implement the entire new IMPROVE equation with CALPUFF is neede d. 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 su bmitted a request for the review of this methodology to EPA and the FLMs.

The VISTAS methodology for implementing th e new IMPROVE equation using existing CALPUFF/CALPOST output is contained in a spreadshee t developed by Dr. Ivar Tombach. The VISTAS procedure is essent ially 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 he aring on the State’s Regional Haze State Implementation Plan (SIP ) submittal. A generic approval for all applications of this alternative method w ill not be provided. EPA approval will be granted on a case-by-case basis, considering th e merits of the State’s request including supporting documentation for using the alte rnative methodology for the BART modeling.

8

### 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 provi ded 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 procedur es used in the modified-post processing methodology (e.g., spreadsheet or other post-processing calculations with explicit discussion on the limitations and assump tions in developing the data inputs).

Additionally, consistency should be maintained when applying the new vs. old equations when calculating natural background, current, an d future visibility impacts at Class I Areas. For example, if the new IMPROVE e quation is used to calculate the natural background visibility impact for a Cla ss 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 spre adsheet developed by Dr. Ivar Tombach appropriately implements the features of the new IMPROVE equation, with the exception of the nitrogen dioxide term. The met hodology 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/m 3 

### , 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.co lostate.edu/IMPROVE/Publications/GrayLit/019_RevisedIMPROVEeq /RevisedIMPROVEAlgorithm3.doc ) 

### . The methodology also incorporates the new sizefraction specific f(RH) factor s contained in the technical support document. These new procedures are used to calculat e the visibility impacts from the source and also to adjust natural background values (to a ccount for sea salt and the bimodal split of sulfates, nitrates and organics). Th e background value is appropria tely added to the source concentration for determining the correct size fr action for sulfates, nitrates and organics. The calculated visibility impacts are then co mpared with the adjust ed natural background visibility to determine the change in visi bility impact for the comparison with the

threshold value.

As noted above, the methodology does not adeq uately address the nitrogen dioxide (NO 2 

### ) term in the new IMPROVE equation. It indicates that the NO 2 

### term is small and

9

### insignificant. This may not be the ca se in each specific application. NO 2 

### concentrations are not readily available from CALPUFF/ CALPOST when using the default MESOPUFF II chemistry option. Therefore, EPA Re gion 4 has determined that it would be acceptable to use the total NO

x 

### concentration as a surrogate for NO 2 

### (i.e., conservatively

assume that all NO

x 

### is NO 2 

### ). The total NO

x 

### concentration can easily be obtained by turning on the switch to produce NO

x 

### concentration output wh en running CALPOST– no changes to the CALPUFF modeling are needed. The NO

x 

### concentration is obtained in CALPOST using the following option in Input Gr oup 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.

10

### 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 – Result s of BART Modeling & Engineering Analysis @ Maximu m 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 visi bility 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 ag ree 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 98 th 

### 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 incl ude the nitrogen dioxide (NO 2 

### ) term. The

details of the calculations are contained in a MS Excel spreadsheet included on the compact discs in Appendix 3 of th e report. The calculations of the NO 2 

### term are missing from the spreadsheet. No e xplanation is given for omission of the

NO 2 

### term. We believe that the NO 2 

### term should be included whenever the new IMPROVE equation is used. Also, the levels of NO

x 

### emissions from the DuPont facility are too la rge to ignore the NO 2 

### term.

To evaluate the impact of not including the NO 2 

### term in the new IMPROVE equation, we conducted some hypothetical calculations using the PSD NO

x 

### Class I area increment (2.5 ug/m3 = 1.3 ppb) and the PSD NO

x 

### 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 NO

x 

### emissions rates from the facility (1056 tons/yr from boiler 20 a nd 786 tons/yr from boiler 24). Assuming

either of these values for NO

x 

### concentration at the Class I area results in the

### eighth-high delta-dV impact for Mammo th Cave @ 24-hr maximum emission rates in 2003 exceeding 0.5 dV when the NO 2 

### 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 includ e the NO2 term in the new IMPROVE calculations, we believe that DuPont has not met the exemption modeling criteria. Therefore, the BART determination and ev aluation 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 – Result s of BART Modeling & Engineering Analysis @ Maximu m 24-hour Firing Rates Using the Old IMPROVE Equation , dated September18, 2007.

1. Section 2.1, Revised Modeling Basis fo r 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 argumen ts are reasonable, but we believe that it is not appropriate to us e 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 emi ssions during the summer months. The year-round 24-hr maximum value should still be used for the non-summer months. This would require an additi onal 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 th resholds developed

in the Clean Air Interstate Rule (CAIR) which are $1700/ton for NO

x 

### and $1800/ton for SO2. However, we do not th ink that these should be considered absolute limits, but are good “ball-park” esti mates. Any controls that have costs

close to these thresholds should be considered for BART.

### 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 potenti ally be a cost-effective control option. Also, the use of Low- NO

x 

### Burners on Boiler 20 Only or both Boilers 20&24 appears to also be potenti ally cost effective. Therefore, we recommend that TDEC carefully consider these as possibl e BART controls for the facility.

On Page 18, DuPont states that NO

x 

### reductions from poten tial controls do not result in significant visibility improve ments. We agree that the visibility improvements from the NO

x 

### controls are much less than those predicted for the

SO 2 

### 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 SO 2 

### control options. Therefore, it is more important to carefully

consider controls of SO 2 

### than controls on NO

x 

### when making the BART

determination.

4. Section 4, Conclusions, Page 21:

The Class I area being impacted is Mammo th Cave National Park located in Kentucky. A decision on significance of impacts should be made in consultation with the Kentucky Department for Envi ronmental Protection (KY DEP) and the National Park Service (NPS). It is importa nt to consider the decisions KY DEP is making for other sources impacting Mammo th Cave. This consultation process

should also be documented in the SIP.

### 4APT-APB

Mr. Barry R. Stephens, P.E. Director

Tennessee Division of Air Pollution Control

9 th 

### 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 East man 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 pack age for our consideration. If you have questions regarding this lett er, please contact Jimmy Hou of the Region 4 staff at (404)

562-8965.

Sincerely,

Kay T. Prince

Chief Air Planning Branch

Enclosures

### 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 precip itator 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 ar e proposed to be much lower than the 0.07 lb/MMBtu MACT rate requirement. Th e 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 c ontent is listed as a contro l for the B-252-2A-E, B-83-2C, B6C-1A and B-6C01B emission units. The tabl e 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 pro cedures 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 use d. This assumption needs to be supported for the scrubbers as they typically have a 20 y ear 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) clar ify that consideration should be given not only to add-on controls but also impr ovement in the performance of existing controls and P2. The analysis does not disc uss the facility’s eval uation of options for P2 and process changes for th e 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 ot her 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 Tenne ssee 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 sp ray dryer absorbers

2

### with fabric filters or caustic scrubbers on Boilers 25-29 to achieve the New Source Performance Standard (40 CFR Part 60, Subpa rt Db) for control of sulfur dioxide. Section 6 contains a brief descriptio n 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 subm ittal (Attachment A to these comments provides the Q&A that addresse s this issue). We recommend that the suggestions in the attached Q&A be followe d 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 enfo rceable 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 dem onstrate that the emission reductions from each pollutant being controlled for BART would be equal to those reductions that would be obtained by simply controlli ng 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 Regiona l Haze state implementation plan (SIP) documentation when either the report or SI P is submitted to address EPA concerns. A summary table that pres ents the different control scenarios modeled, cost information, modeled baseline and improveme nt, modeled emission rates, amount of reductions achieved by pollutants and whethe r 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

S O 2

NOx

PM SO2 units

NOx units

PM units

S O 2

NOx

PM SO2 units

NOx units

PM units

S O 2

NOx

PM SO2 units

NOx units

PM units



### 3

### 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 elect rical generating units and power plants, no such threshold for the BART determination of visibility improvement has been recommended. The BART guidelines indi cate 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 pa ge 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 so me 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 th e 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 modeli ng 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 factor s in any modeling exercise is to ensure that the source paramete rs (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.

4

### 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 th e 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 CALPU FF modeling system. Its use should be justified on a case-by-case basis. A deta iled justification which addresses the rationale for using the new equation a nd the performance of the new equation versus the old equation should be pr ovided. Attachment B provides EPA Region 4’s review of the use of the VI STAS 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 NO 2 

### data, the year or years us ed to develop this data and why those years were used. EPA Region 4 has determined that it would be acceptable to use the total NO

x 

### concentration as a surrogate for NO 2 

### (i.e., conservatively assume that all NO

x 

### is NO 2 

### ). The total NO

x 

### concentration can easily be obtained when running CA LPOST by turning on the switch to produce NO

x 

### concentration output – no cha nges to the CALPUFF modeling

are needed.

c. Sea Salt: Documentation on how sea sa lt 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 fo r modeled visibility improvement: We appreciate Eastman TNO providing se veral alternative approaches to determine the visibility improvement fo r the suite of controls used in the

BART determination. It should be note d 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 th e visibility improvement criteria, we recommend that the change in delta deciview between the baseline and different scenarios should be report ed 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 cont rol. Based on this criterion, all control scenarios indicate significan t visibility improvement. d. It is unclear what an average deciview per year metric that is developed from all Class I areas impacted by the East man 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 th at is the case and then improvement at

5

### 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 sc enario 2 for Linville Gorge under the 2003 daily 8 th 

### 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, visibili ty impairing pollutants and potential

emissions. The list or table should illust rate 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 presen tation may be accessed on the following website: http://www.epa.gov/regi on4/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 di scussion could be included in chapter 4.0.

6

### Attachment A

Excerpt from August 24, 2006 Q&A Document

4. How should a State document in the SIP th at 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 cont rols 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 requirem ents 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) mu st begin to comply with the BART limit. Because the BART requirements ar e ‘‘applicable’’ requirements of the CAA, they must be included as titl e 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 i ssuance. This may require that States provide commitments in the SIPs to en sure 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, mu st be addressed to ensure the BART controls are adopted in to the State’s SIP. These elem ents are discussed in detail

with other circumstances in 40 CF R Part 51, Appendix Y – Section V.

• Name of source facility and the specific emission units and pollutants being controlled. (40 CF R 51.308(e)(1)(i) & (ii)).

• Specifics of the controls, control e fficiency(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 maintaine d. (40 CFR 51.308(e)(v))

• Reporting, monitoring, and recordkeep ing 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).

7

### ATTACHMENT B

U.S. EPA Region 4 Review of the VIST AS Methodology for Implementing the New IMPROVE Equation with CALPUFF for BART Modeling

The original Interagency Monitoring of Pr otected 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 co mpound 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 sa lt, which is important at sites near the ocean coasts. As a result of these limitations, the IM PROVE Steering Committee commissioned the development of a new IMPROVE algorithm, wh ich 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 ne eded to process the mass concentrations from CALPOST using the new IMPROVE equati on so that the Best Available Retrofit Technology (BART) analyses could consider bo th 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/CALPOS T data to implement the entire new IMPROVE equation with CALPUFF is neede d. 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 su bmitted a request for the review of this methodology to EPA and the FLMs.

The VISTAS methodology for implementing th e new IMPROVE equation using existing CALPUFF/CALPOST output is contained in a spreadshee t developed by Dr. Ivar Tombach. The VISTAS procedure is essent ially 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 alternativ e method should be made by each individual State allowing time for EPA Region 4 approval prior to the public he aring on the State’s Regional Haze State Implementation Plan (SIP ) submittal. A generic approval for all applications of this alternative method w ill not be provided. EPA approval will be granted on a case-by-case basis, considering th e merits of the State’s request including supporting documentation for using the alte rnative methodology for the BART modeling.

8

### 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 provi ded 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 procedur es used in the modified-post processing methodology (e.g., spreadsheet or other post-processing calculations with explicit discussion on the limitations and assump tions in developing the data inputs).

Additionally, consistency should be maintained when applying the new vs. old equations when calculating natural background, current, an d future visibility impacts at Class I Areas. For example, if the new IMPROVE e quation is used to calculate the natural background visibility impact for a Cla ss 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 spre adsheet developed by Dr. Ivar Tombach appropriately implements the features of the new IMPROVE equation, with the exception of the nitrogen dioxide term. The met hodology 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/m 3 

### , 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.co lostate.edu/IMPROVE/Publications/GrayLit/019_RevisedIMPROVEeq /RevisedIMPROVEAlgorithm3.doc ) 

### . The methodology also incorporates the new sizefraction specific f(RH) factor s contained in the technical support document. These new procedures are used to calculat e the visibility impacts from the source and also to adjust natural background values (to a ccount for sea salt and the bimodal split of sulfates, nitrates and organics). Th e background value is appropr iately added to the source concentration for determining the correct size fr action for sulfates, nitrates and organics. The calculated visibility impacts are then co mpared with the adjust ed natural background visibility to determine the change in visi bility impact for the comparison with the

threshold value.

As noted above, the methodology does not adeq uately address the nitrogen dioxide (NO 2 

### ) term in the new IMPROVE equation. It indicates that the NO 2 

### term is small and

9

### insignificant. This may not be the ca se in each specific application. NO 2 

### concentrations are not readily available from CALPUFF/ CALPOST when using the default MESOPUFF II chemistry option. Therefore, EPA Re gion 4 has determined that it would be acceptable to use the total NO

x 

### concentration as a surrogate for NO 2 

### (i.e., conservatively

assume that all NO

x 

### is NO 2 

### ). The total NO

x 

### concentration can easily be obtained by turning on the switch to produce NO

x 

### concentration output wh en running CALPOST– no changes to the CALPUFF modeling are needed. The NO

x 

### concentration is obtained in CALPOST using the following option in Input Gr oup 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.

10Alcoa Tennessee Operations 2300 North Wright Road
Alcoa, TN 37701-3141 USA 

# a

January 10, 2008

Mr. Barry Stephens, Technical Secretary
Tennessee Division of Air Pollution Control

9 th 

### Floor, L & C Annex
401 Church Street Nashville, Tennessee 37243-1531

Re: Response to Comments on the Best A vailable 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 submitti ng the attached responses to specific

comments received on the best available retr ofit 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 perc ent sulfur content is infeasible will require extensive supporting documentation, since coke suppliers can produce coke with a sulf ur 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, refiner ies are left with a residual material made up of high molecular weight hydroc arbons. 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 co ke (by-product) and produce lighter fraction liquids that can be further dist illed 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 co ke that provides an appropriate coefficient of thermal expansion (CTE) and an acceptable level of porosity. An appropriate CTE is important bec ause 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 par ticles. 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) appr opriate coke structure (quantity, size, and shape of pores), and 5) appropr iate microtexture. Of the four cokes produced from a delayed coker, s ponge 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 annua lly. To meet demand, producers are expected to revamp existing refinerie s and construct new refineries that maximize light product yields from hi gh sulfur crudes, allowing refiners to capitalize on the significant price di fference between high and low sulfur crude oils. The current price differ ential between high and low sulfur crude oils is already driving exis ting 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 refiner ies. In 2005 worldwide anode grade calcined coke consumption represent ed 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 pr oduct quality of the green petroleum coke. As such, the aluminum industr y has little influence in controlling the quantity, quality, and the price of t he coke produced by refineries

Page 3 of 12

### The deterioration in coke quality and t he tightness of supply is expected to
continue for the foreseeable future. As a result, Alcoa’s Tennessee smelter is unable to guarantee complianc e with a coke sulfur content of less than 3%, because the future ava ilability 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 par ameters 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 exem ption: The exemption threshold value selected by the State in determining whether a BART-eligible source can reasonably be anticipated to cause or contri bute to visibility impairment must be documented in the State Impl ementation 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 th reshold, States should consider the number of emission sources affecting t he 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 thre shold used by the State will be subject to public review and comment, and States could consult with the affected States or Regional Planning Or ganizations or Federal Land Managers in establishing this value.

Alcoa Response: Alcoa assumes the TDAPC will address this comment.

3. BART-Eligible Units: We suggest t hat the documentation for the BART SIP requirements include a list of all emissi on 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 consider ed BART eligible. If BART-eligibility is based on specific dates and later determi ned 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 Pot lines 1 and 2 and the anode bake furnace are already equipped with sophistic ated emission control equipment for PM, so the
BART determination for these emission units focuses primarily on potential
reductions for S02 and NOx. The subm ittal should also discuss why the "sophisticated emission cont rols" 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 r epresent the best
available control for these units. Sinc e the emissions from these units are claimed to be insignificant, it is important to assure that the emissions controls are operated properly. Theref ore, the BART determinat ion should ensure that there are permit conditions requiring the baghouses to be pr operly operated and

maintained.

Alcoa Response: Permit conditions for these em ission units requiring proper operation and maintenance are already in cluded 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 IM PROVE 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 c hange is not the Visibility Improvement -
State and Tribal Associati on of the Southeast (VISTAS) model that has been agreed upon for use in the BART modeli ng. It has not been sufficiently and clearly demonstrated that the new CA LPOST provides a better method to incorporate the new IMPR OVE equation into the CALPUFF modeling system. In

order to use a version other t han 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 (Met hod 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 r egarding Alcoa’s BART determination.

Page 6 of 12

### Modeled 98 th 

### Percentile (deciviews)
Class 1 Area Method 6 Method 8

1.273 1.092

1.189 0.966 Great Smoky Mountains

1.620 1.310

0.385 0.301

0.446 0.363 Linville Gorge
0.475 0.370

0.462 0.375

0.493 0.463 Shining Rock

0.359 0.293

0.511 0.474

0.677 0.549 Joyce-Kilmer/ Slickrock

0.837 0.686

0.499 0.427

0.413 0.335 Cohutta

0.492 0.414

d. There is no documentation on how t he version of CALPOST with Method 8 was developed. Quality assurance that was used in its development, coding and integration of the new equat ion with CALPUFF to develop visibility impacts was

not discussed.

Alcoa Response: Details on the CALPOST calcul ation are provided in the Final Modeling Report (Appendix B of the BART Determination Report). The
CALPOST code with Method 8 was subm itted 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 To mback that has been reviewed and approved by the FLMs and EPA.

e. It is incumbent upon the state and the fac ility 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 guidanc e 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 re port contains a detailed description of the new IMPROVE equations implemented as Method 8 in CALPOST. Figure 1 of the Appendix c ontains 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 out put 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 ni trate 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 out put 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 spreads heet 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, t he 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 equati on coupled with the modified CALPOST processor is not a generic model that EPA Region 4 re cognizes to be a part of the CALPUFF modeling system. Its use should be justifi ed on a case-by-case basis. A detailed

Page 8 of 12

### justification, which addresses the rati onale 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 spreadshee t, especially when multiple years of data and multiple Class I areas are involved.

j. Nitrogen dioxide concentrations: The r eport 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 conc entration 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, m eaning 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 S ea Salt tab of Ivar Tombach’s spreadsheet.

j. Referencing a method to use t he 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 Pitchf ord et al. (2007) referenced above. Also, note the comments regardi ng 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-kilome ter (km) grid resolution modeling was used in the refined modeling of the facility. The documentation on the development of the l-km meteorologica l data using CALMET was incomplete.
The documentation should discuss the CALM ET 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. De scriptions 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 Modeli ng 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. Contro l Scenario 2 is listed as "3.0% Sulfur Coke." Based on the modeling results pres ented 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 s hould 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 SO 2 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 sim ilar sources, and individual or group contributions were summed at the end.”

2. Even though the submittal indicates t hat 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 subm itted 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 consis tent 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 t he 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 SI P why the 0.5 visibility threshold was applicable for the BART ex emption modeling. The State should

also document whether a 0.5 dv threshol d should be used to determine visibility improvement for tile BAR T determination modeling.

Alcoa Response: Alcoa assumes the TDAPC will respond to this comment.

5. It is unclear what version of CALM ET, 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, consist ent with the protocol submitted in June 2006. More specifically, following VIST AS 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 refe rring to the BART Analysis for Columbia Falls Aluminum Company (CFAC) in Columbia Falls, Montana:

“On pages 4-5 and 4-10 to 4-13, CF AC discuss switching from its
current 1.5% S coke to coke wit h as little as 0.5% S. I would appreciate it if you could investi gate 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.

### 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 assu med 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 t he 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 esti mated based on this EPA assumption. As shown in Table 2 (page 5), the cost of dis posal was assumed to be $2/1000 gal, which

comes from the same EPA cost manual.

• EPA recognizes that the facility consider s 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 PM 10 

### ?

The existing ESPs at TVA Cumberland Fossil Plant consistently perform with excellent capture efficiencies. Recent co mpliance 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 t he following statement whether the Gallatin plant is expect ed to be controlled by 2018: "TVA has indicated that it will ultimately contro l 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 ai r plan based on compliance with Phases

I and II of CAIR and CAMR that will invol ve installation of s ubstantial additional controls on various units across their system into the next decade. These controls are in addition to those already installed and currently under construc tion. To ensure that

TVA makes the best economi c 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 thei r system by re-powering, additional fuel switching, installing additional controls on uni ts 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 provid es the optimum compliance strategy.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 Stat e 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-elig ible source that may reas onably 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 Appe ndix Y, the State has identified the BART-eligible sources located at your facility. Please contact Julie Aslinger if you have questi ons 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.

### 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 Mo del for Analyses of Best Available Retrofit Technology (BART)”, 12 km CALMET (CALMET is a meteorological da ta 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 Asli nger at (615) 532-0587 or Julie.Aslinger@state.tn.us. The CALMET data sets are rather large. For data transfer pur poses, you will need to provide an appropriate size fire wire or USB drive onto which the data will be copied. Yo u must also include a prepaid and addressed postage label for shipping the drive back to you.

### 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

BRSSTATE 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 Stat e 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-elig ible source that may reas onably 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 Appe ndix Y, the State has identified the BART-eligible sources located at your facility. Please contact Julie Aslinger if you have questi ons 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.

### 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 Mo del for Analyses of Best Available Retrofit Technology (BART)”, 12 km CALMET (CALMET is a meteorological da ta 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 Asli nger at (615) 532-0587 or Julie.Aslinger@state.tn.us. The CALMET data sets are rather large. For data transfer pur poses, you will need to provide an appropriate size fire wire or USB drive onto which the data will be copied. Yo u must also include a prepaid and addressed postage label for shipping the drive back to you.

### 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

BRSSTATE 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 Stat e 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-elig ible source that may reas onably 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 Appe ndix Y, the State has identified the BART-eligible sources located at your facility. Please contact Julie Aslinger if you have questi ons 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):

### 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 Mo del for Analyses of Best Available Retrofit Technology (BART)”, 12 km CALMET (CALMET is a meteorological da ta 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 Asli nger at (615) 532-0587 or Julie.Aslinger@state.tn.us. The CALMET data sets are rather large. For data transfer pur poses, you will need to provide an appropriate size fire wire or USB drive onto which the data will be copied. Yo u must also include a prepaid and addressed postage label for shipping the drive back to you.

### 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

BRSSTATE 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 Stat e 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-elig ible source that may reas onably 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 Appe ndix Y, the State has identified the BART-eligible sources located at your facility. Please contact Julie Aslinger if you have questi ons 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.

### 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 Mo del for Analyses of Best Available Retrofit Technology (BART)”, 12 km CALMET (CALMET is a meteorological da ta 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 Asli nger at (615) 532-0587 or Julie.Aslinger@state.tn.us. The CALMET data sets are rather large. For data transfer pur poses, you will need to provide an appropriate size fire wire or USB drive onto which the data will be copied. Yo u must also include a prepaid and addressed postage label for shipping the drive back to you.

### 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