# Best Available Retrofit Technology (BART) Analysis
Eastman Business Park

Submitted To: NYSDEC Division of Air Resources 625 Broadway Albany, NY 12233-3250
Prepared For:
Eastman Kodak Company 1669 Lake Ave Rochester, NY 14652-4543 Duke Energy Generation Services 3800 Dewey Avenue, Suite 325 Rochester NY 14616
Prepared By: Epsilon Associates, Inc. 3 Clock Tower Place Suite 250 Maynard, MA 01754
September 29, 2010

### Re: 

# DB#tfn. 3800 Dewey Avenue, Suite 325 Rochester,

NY 14616 585-58&.6982 585-58&4550

fax

SUEZ-DEGS

ofRocfiesfer



### September

29,20rc

Scott Griffin NYSDEC Division of Air Resources Regional Haze BART Rule 625 Broadway Albany, NY 12233-3251 sr8-402-8396

BART Analysis Eastman Business

Park, Rochester

New York

Dear Mr. Griffin,

Enclosed are two copies of the Best Available Retrofit Technology @ART) Anatysis

for the Eastman Business Park Boilers operated

by SUEZ-DEGS

of Rochester,

submitted

per the requirements

of 6 NYCRR Part 249.

We are aware of at least two other regulatory programs (NESHAPs and NOx RACT) that will soon impose new air quahty requirements on the coal-fired boilers at the Eastman Business

Park. We are concerned that the boilers will become subject to conflicting requirements,

or that the implementation schedule for one set of requirements will force us to select and install add-on controls before knowing that the controls will satisfy

all the other requirements.

For BART, we propose as the best emission

control option a restriction on the simultaneous
use of the boilers. This will provide assurance that visibility impacts at Class I areas are minimized,

while allowing

us the flexibility to respond to other upcoming

requirements

as new regulations

are finalized.

AfteTNYSDEC's initial review of the BART Analysis, w€ would like to meet

to discuss

next steps. Please

contact Jill Wood, Senior

EHS Professional

for SUEZ-DEGS

of Rochester,

at your convenience

at 585-588-6982

or iill.wood@duke-energy.com to discuss.

Edward R. Siler Plant Manager Suez-DEGS

of Rochester

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Suite 325 Rochester,

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### Cc: NYSDEC Region I Office ATTN: Thomas lVIarriott, 6274

East Avon Lima Roa4 Avon, hIY 14414

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## TABLE OF CONTENTS

1.0 INTRODUCTION 1-1 1.1 Best Available Retrofit Te chnology Requirement 1-1 1.2 Eastman Business Park Overview 1-2 1.3 BART-Eligible Sources At Eastman Business Park 1-2 1.4 Related Air Quality Requirements for Coal-Fired Boilers 1-4 1.5 Outline of Analysis 1-4

2.0 CONTRIBUTION TO VISIBILITY IMPAIRMENT 2-1 2.1 Emission Rate Calculations 2-1 2.2 CALPUFF Visibility Modeling 2-3 2.3 CALPOST Processing of Visibility Impacts 2-5

3.0 CONTROL TECHNOLOGIES 3-1 3.1 Sulfur Dioxide Control Options 3-1 3.2 Nitrogen Oxides Control Options 3-3 3.3 Particulate Matter Control Options 3-5 3.4 Other Control Options 3-7

4.0 CONTROL EFFECTIVENESS 4-1

5.0 FIVE-FACTOR ANALYSIS 5-1 5.1 Costs of Compliance 5-1 5.2 Energy & Non-Air Quality Environmental Impacts 5-2 5.3 Existing Pollution Control Technology 5-3 5.4 Remaining Useful Life of the Source 5-3 5.5 Degree of Visibility Improvement 5-3

6.0 VISIBILITY ANALYSIS 5-1 6.1 Emission Rate Calculations 5-1 6.2 CALPUFF Modeling 5-1 6.3 CALPOST Processing of Visibility Impacts 5-1 6.4 CALPUFF/CALPOST Results 5-2

7.0 BEST EMISSION CONTROL OPTION 5-1

APPENDICES Appendix A Supporting Calculations Appendix B Air Quality Dispersion Modeling Analysis Documentation

2846/BART Analysis 9-29.doc i Table of Contents2846/BART Analysis 9-29.doc ii Table of Contents 

## List of Figures

Figure 1-1 Site Plan Figure 1-2 Orthophoto Figure 2-1 Modeled Class I Areas



## List of Tables

Table 2-1 Emission Rates used in CALPUFF Baseline Modeling Table 2-2 Source Parameters Table 2-3 CALMET Platforms Table 2-4 Visibility Impacts (delta deciview) Predic ted using the VT-NWS Meteorological Data Set Table 2-5 Visibility Impacts (delta deciview) Predic ted using the Hybrid Meteorological Data Set Table 5-1 Baseline & Restricted Operation Emission Rate Table 5-2 Summary of Control Costs Table 5-3 Energy & Non-Air Quality Environmental Impacts Table 5-4 Visibility Improvement Cost-Effectiveness Table 6-1 Maximum and 98% 24 hr Visibility Impact, Base Case Table 6-2 Visibility Impact for Pre- and Post-BART Control Table 6-3 Number of Days Exceeding 0. 1, 0.5, and 1.0 Deciview

## 1.0 INTRODUCTION

1.1 Best Available Retro fit Technology Requirement
Eastman Business Park has been identified by the New York State Department of Environmental Conservation (NYSDEC) as having emission units subject to regulation under the Best Available Retrofit Technology (BART) regulations. BART is required by the U.S. EPA Regional Haze Regulations desi gned to improve visibility in the Federal Class I Areas. A BART-eligible unit is a source at a stationary facility that:
Falls into any of the 26 source categories id entified under the Regional Haze Regulations [40 CFR 51, July 6, 2005];
Began operation after August 7, 1962, and was still in existence on August 7, 1977; and,
Has the potential to emit 250 tons per year (tpy) or more of any visibili ty impairing pollutant [including sulfur dioxide (SO 2 

### ), oxides of nitrogen (NO x 

### ), particulate matter (PM10), and volatile organic compounds (VOCs)].
The U.S. EPA BART Guidelines provide gen eral recommendations for conducting BART assessments, but essentially leave it up to the i ndividual states to determine the approach to be taken in the visibility assessment and the a ssociated determinations leading to the best option for choosing BART. New York State has promulgated BART regulations in 6 NYCRR Part 249, which incorporates the general re commendations of EPA in their approach.
The federal rule lists five steps for a BART analysis:
STEP 1—Identify All Available Re trofit Control Technologies,

STEP 2— Eliminate Techni cally Infeasible Options,
STEP 3— Evaluate Control Effectiveness of Remaining Control Technologies,
STEP 4— Evaluate Impacts and Document the Results, and
STEP 5—Evaluate Visibility Impacts.
New York specifies a 5-Factor BART anal ysis which incorporates the following:

1. Cost;

2. Energy and non-air quality environmental impacts;

3. Existing controls at the source;

4. The remaining useful life of the source; and

2846/BART Analysis 9-29.doc 1-1 Introduction

### 5. The visibility improvement reasonably expected from the control technology options (demonstrated through CALPUFF visibility modeling).
This assessment is for the feasibility of cont rol of regional haze precursors, specifically: sulfur dioxide (SO 2 

### ), nitrogen oxides (NO x 

### ), and particulate matter (PM).


### 1.2 Eastman Business Park Overview
Eastman Business Park occupies approximately 1, 220 acres of land in New York State. The facility is located in north central Monroe Co unty, and the developed portion of the site is bounded by the Genesee River to the east, Route 104/Eastman Avenue to the north, Ridgeway Avenue to the south, and Route 390 to the west. Sections east of Mount Read Boulevard are in the City of Rochester; most sections west of Mount Read Boulevard are within the Town of Greece. The longest east/west dimension is about three miles, while the maximum north/south dimension is about one mile. A large number of buildings and structures are located throughout the facility, with generally increasing density west to east. These buildings contain the many different K odak processes involved in the manufacture of imaging products, including photographic films, papers, and chemicals. In addition, multiple tenant operations are also located at the site. On site utility services (water, steam, electricity, refrigeration and wastewater treatm ent) are provided to both Kodak operations and the tenants.
Eastman Kodak Company has two separate Title V permits covering operations at Eastman Business Park. One permit (NYSDEC # 8-2614- 00205/01801) covers Kodak manufacturing operations. A separate Title V permit (NYS DEC # 8-2614-00205/01827) was issued for the purpose of designating SUEZ-Duke Energy Gene ration Services of Rochester (SDEGS) as the operator of Kodak's combustion installation units at Buildings 31 and 321 within the Eastman Business Park facility. 

### 1.3 BART-Eligible Sources At Eastman Business Park
Eastman Kodak Company owns and SDEGS oper ates two steam and electric generating stations at Eastman Business Park (EBP). The pr imary function of both stations is to provide the necessary energy needs for supporting Kodak manufacturing operations and on-site
tenants.
One station, Building 321, is located at the West end of EBP. The following sources are located at the Building 321 station:

1) BART-eligible Boiler 41 (called 3A in EP A’s Clean Air Market Division database);

2) BART-eligible Boiler 42 (called 3B in EPA’s Clean Air Market Division database);

3) BART-eligible Boiler 43 (called 4A in EP A’s Clean Air Market Division database);

2846/BART Analysis 9-29.doc 1-2 Introduction

### 4) Boiler 44 (called 4B in EPA’s Clean Air Market Division database); and

5) BART-eligible sources of Particulate Matter (PM) associated with coal ash storage and transfer operations.
Boilers 41, 42 and 43 are cyclone fired boilers burning bituminous coal with natural gas reburn to reduce NO x 

### and SO 2 

### emissions. Each has an existing dry electrostatic precipitator (ESP) to control particulate matter. Boiler 44 is not subject to BART because it was built after August 7, 1977 and is instead subject to federal New Source Performance Standards. Boilers 41 & 42 share a stack, and Boilers 43 & 44 share a stack; both stacks are slightly over 400 feet tall.
Figure 1-1 shows a site plan of the Building 321 station. Figure 1-2 is an orthophoto of the

area. The second station, Building 31, is located appr oximately 1.5 miles to the east of Building 321. Four BART-eligible oil-fired package bo ilers are located in Building 31. Exemption modeling as specified in the NYSDEC protocol (dated 2/25/2010) was performed for these sources and the results are documented in Tabl es 2-4 and 2-5 in this report. In accordance with 6 NYCRR 249.1(c)(3), the package boilers at Building 31 do not or will not emit any combination of visibility impair ing pollutants that results in a visibility impairment equal to or greater than 0.1 deciviews in any Federal Class I Area and therefore these sources are exempt from the provisions of Part 249.
Based on maximum daily emission levels for the coal ash storage and transfer operations at Building 321 that are significantly lower than the maximum daily emission levels for the package boilers and the signifi cantly lower stack heights fo r the coal ash storage and transfer operations and in accordance with 6 NYCRR 249.1(c)(3), it is Kodak’s conclusion based on engineering judgment that the coal ash storage and transfer operations at Eastman Business Park do not or will not emit any combin ation of visibility impairing pollutants that results in a visibility impairment equal to or greater than 0.1 deciviews in any Federal Class I Area and that these sources are also exempt from the provisions of Part 249.

In addition to emission sources associated with steam and electric generating operations at EBP, Eastman Kodak Company ow ns and operates multiple small BART-eligible sources of SO 2 

### , NO x 

### and PM associated with Kodak manufacturing operations. The BART determination for these sources has been su bmitted to the NYSDEC under separate cover (Letter from Michael Zapkin, Kodak to Robe rt Sliwinski, NYSDEC; September 9, 2010).

2846/BART Analysis 9-29.doc 1-3 Introduction

### 1.4 Related Air Quality Requirements for Coal-Fired Boilers

In addition to the 6 NYCRR Part 249 BART re quirements addressed by this analysis, the coal-fired boilers at Eastman Business Park are subject to Reasonably Available Control Technology (RACT) requirements under 6 NYCRR Part 227-2 and CAIR NO x 

### Ozone Season Trading Program requirements under 6 NYCRR Part 243. If finalized as-proposed, these boilers will also be subject to National Emission Standards for Hazardous Air Pollutants under 40 CFR 63 Subpart DDDDD. Given these related requirements, and the rapidly shifting regulatory landscape, Kodak and SDEGS want to work with NYSDEC to identify a single cost-effective compliance solution with a rational implementation schedule. 

### 1.5 Outline of Analysis
The remainder of this application is organized as follows:
Section 2 describes the modeling analysis performed to determine the contribution to visibility impairment in Class I areas;
Section 3 identifies all available control technolog ies and eliminates te chnically infeasible control options;

Section 4 evaluates control effectivene ss of remaining control technologies;
Section 5 evaluates impacts using the five-f actor analysis and documents the results;
Section 6 evaluates visibility impacts; and
Section 7 reports the best option for emission control equipment for the purpose of improving visibility conditions.
Appendix A contains Supporting Calculati ons, and Appendix B provides air quality modeling documentation.

2846/BART Analysis 9-29.doc 1-4 IntroductionFigure 1-1Site PlanEastman Business Park BART Analysis Rochester, New YorkWeiland Rd G:\Projects2\NY\2846\aerial.mxd



### Figure 1-2 Aerial Locus 

### Eastman Business Park BART Analysis Rochester, New York Basemap: 2010 Aerial Imagery, Google Earth Pro Scale 1:2,400 1 inch = 200 feet 

# ° 0 100 200 Feet

## 2.0 CONTRIBUTION TO VI SIBILITY IMPAIRMENT

NYSDEC has developed a modeling protocol (d ated 2/25/10) based on discussions with the involved agencies, including EPA Region 2, Vermont Department of Environmental Conservation (VTDEC), and the Federal Land Mana gers (FLMs) for Class I areas. In the protocol, NYSDEC defines a set of default reco mmendations to be used for the modeling of BART sources in New York in order to calculate the net improvements in visibility at a set of seven Class I areas.
Boilers 41, 42, 43 and the package boilers were modeled using the procedures in the NYSDEC modeling protocol to determine th eir contribution to visibility impairment.


### 2.1 Emission Rate Calculations
Emission rates are calculated based on best available data following EPA and NYSDEC guidance. Specifically, EPA has the following guidance in the final BART rule (70 FR 39162, emphasis added):
The emissions estimates used in the models are intended to reflect steadystate operating conditions during periods of high capacity utilization. We do not generally recommend that emissions reflecting periods of start-up, shutdown, and malfunction be used, as such emission rates could produce higher than normal effects than woul d be typical of most facilities. We recommend that States use the 24 hour average actual emission rate from the highest emitting day of the meteorolog ical period modeled, unless this rate reflects periods start-up, shutdown, or malfunction.

The document NYSDEC Guidance and Protocol for Vi sibility Modeling of BART Eligible Sources (February 25, 2010) says: The maximum 24 hour actual source emissions should be determined by each source, using data over the last 5 years of representative operations, and demonstrate to the satisfaction of NYSDEC staff as appropriate before any modeling is submitted.
Based on this guidance the following data were used to determine the maximum 24-hour actual source emissions.
Nitrogen Oxides (NO x 

### ): For Boilers 41, 42 and 43, historical Continuous Emissions Monitoring System (CEMS) data were queried for the highest NO x 

### mass emissions for calendar years 2005-2009. Those were cross-checked against the reported data in EPA’s Clean Air Markets Division (CAMD) online data base for the individual days. The emission rates were converted from pounds per day to grams per second for model input.

2846/BART Analysis 9-29.doc 2-1 Contri bution to Visibility Impairment2846/BART Analysis 9-29.doc 2-2 Contri bution to Visibility Impairment 

### Sulfur Dioxide (SO 2 

### ): For Boilers 41, 42 and 43, coal sulfur content is tracked by shipment; and that coal is burned for a predictable nu mber of days after the shipment arrives. Maximum 24-hour SO 2 

### emission rates were calculated based on the highest coal-fired heat input rate during the days when the hi ghest sulfur content coal was being fired.

Particulate Matter (PM): For Boilers 41, 42 and 43, the PM emission rates were based on stack test results for both filterable and cond ensable PM. The pound-per-hour test results were used, conservatively assuming 24-hour operation.
For modeling, PM speciation was performed using modified guidance from the National Park Service (NPS). This NPS website 1 

### provides spreadsheets which use the EPA AP-42 particle speciation factors to divide PM emissions into these categories: “Coarse, Fine Soil, Fine Elemental Carbon, Condensable Partic ulate Matter Inorganic, and Condensable Particulate Matter Organic.” These are en tered into the modeling in the following categories: “Coarse, Fine, Elemental Car bon, Sulfates, and Organic Carbon.” The spreadsheet for cyclone furnaces with electr ostatic precipitators was used, modified to reflect the fact that stack test results were available for both filterable and condensable PM fractions.
Package Boiler Emissions : Emissions from the four small package boilers are calculated based on emission factors provided by SDEGS (1.64 lb/MMBtu SO 2 

### , 0.57 lb/MMBtu NO x 

### , 0.1 lb MMBtu filterable PM), plus the EPA AP-42 factor for condensable PM from oil combustion (0.01 lb/MMBtu). These are conv erted to grams per second based on the annual fuel use limit. While this does not reflect the “maximum 24-hour actual source emissions,” the emission rates from the package boilers are a small fraction of the boiler 41, 42, and 43 emission rates. The PM emissions are unspeciated, again because they are a small fraction of the main boiler PM emission rates.

Emission Summary : Since Boilers 41 and 42 vent through a common stack, their emission rates were combined for the modeling. Similarly, the package boilers vent through a common stack, so the emission rate modeled represents the total emissions from all four package boilers. Based on the above methods, emission rate inputs into the CALPUFF modeling are shown in Table 2-1.
Table 2-1 Emission Rates used in CALPUFF Baseline Modeling

Emissions in grams/sec NO x SO 2 PM 10 PM Fine Elemental Carbon SO 4 Organic Carbon Boilers 41 & 42 84.27 474.09 4.92 5.69 0.22 6.08 1.52 Boiler 43 58.50 242.79 3.52 4.0 7 0.16 7.3 7 1.84 Package Boilers (1-4) 0.98 2.81 0.172 0.01 7 0.0 0.0 0.0

1 http://www.nature.nps.gov/air/Permits/ect/ectCoalFiredBoiler.cfm

### 2.2 CALPUFF Visibility Modeling
The BART Modeling analysis follows the NYSDEC Guidance and Protocol for Visibility Modeling of BART Eligible Sources (dated February 25, 2010). The visibility modeling was conducted using the CALPUFF model (Version 5.8, Level 070623), the recommended “default” model. CALPUFF is the EPA guide line model recommended for assessing long range transport impacts in Class I Areas. CALPUFF is a non-steady state Gaussian puff model that uses three-dimensional meteorolog ical data and incorporates complex terrain algorithms, chemical transformations, buildin g downwash, and other effects. Since the modeling domains cover such a large region, to account for the curvature of the earth, Lambert Conformal Conic projection coordinates were used to define source and receptor locations in the domain.
The CALPUFF model was run including Boilers 41, 42 and 43 and the four package boilers at Eastman Business Park using the maxi mum daily emission rates shown above. The modeled source parameters are shown in Table 2-2.

Table 2-2 Source Parameters
Stack Height (m) Stack Diameter (m) Exit Temp (deg K) Exit Velocity (m/s) Boilers 41 & 42 124.4 3.6 424.8 15.5 Boiler 43 124.7 4.6 422.0 13.7 Package Boilers (1-4) 111.6 3.4 472.0 7.0



### Visibility impacts were assesse d in the following Class I ar eas: Lye Brook Wilderness Area in VT, Acadia National Park in ME, Brigantin e Wildlife Refuge in NJ, Presidential Range and Great Gulf Wilderness Areas in NH, and Dolly Sods and Otter Creek Wilderness Areas in WV. The proximity of Eastman Business Park to these areas is shown in Figure 2-1.
A set of receptors has been developed for each Class I area by the National Park Service (NPS)/Federal Land Managers (FLMs). These rece ptors sets are of sufficient density to be used for the CALPUFF visibility modeling. The coordinates of each receptor were converted to Lambert Conformal Conic projecti ons before being used in the modeling. A total of 788 receptors were modeled (103 in Lye Brook, 256 in Acadia, 16 in Brigantine, 188 in Presidential Range, 38 in Great Gulf, 65 in Dolly Sods and 122 in Otter Creek).
The NYSDEC protocol required that two different sets of CALMET generated meteorological data sets be used in the BART modeling. Bo th data sets used 2002 data; however they were developed using different “platforms”. The first developed by the Vermont DEC used National Weather Service observations only with a 36 km grid size, and the other developed by NYSDEC and AECOM used a “hybrid” approach with both NWS observations in conjunction with MM5 wind fields, and a smaller grid size (4 km).

2846/BART Analysis 9-29.doc 2-3 Contri bution to Visibility Impairment

### NYSDEC has provided both of these CALMET data sets for use in the BART modeling. CALPUFF was run separately for each CALMET data set. The CALMET domain parameters are defined in Table 2-3 for each data set.

Table 2-3 CALMET Platforms

VT-NWS CALMET Domain Hybrid CALMET Domain Projection Lambert Conformal Lambert Conformal Projection Origin 40o N, 97o W 40o N, 97o W Parallels of Latitude for Projection 33o N, 45o N 33o N, 45o N False Easting, Northing at Projection Origin 108 km, 720 km 0 km, 0 km

Datum WGS-G (WGS-84 GRS 80) NAS-C (NAD27) Number of Grid Cells nx = 74, ny=60 nx = 263, ny = 325 Grid Spacing 36 km 4 km SW Corner of Grid (1,1) 0 km, 0 km 1288 km, -133 km Number of Vertical Layers 8 11 Cell Face Heights (m) 0, 20, 120, 240, 500, 1000, 1500, 2500, 3500 0, 20, 50, 100, 200, 350, 500, 750, 1000, 2000, 3000, 4000



### As recommended in the NYSDEC protocol, the CALPUFF model was run with the EPA/FLM regulatory switch set. The following options were invoked:

♦ Gaussian distribution;

♦ Near field puffs are modeled as puffs (no slugs);

♦ Chemical transformation rates comput ed using the MESOPUFF II scheme;

♦ Model dry and wet deposition;

♦ Stack tip downwash; and

♦ Pasquill-Gifford dispersion coefficients for rural areas and McElroy-Pooler coefficients for urban areas.
CALPUFF used measured hourly ozone concen trations in the chemical transformation scheme (conversion of SO 2 

### to SO 4 

### and NO x 

### to HNO 3 

### and NO 3 

### ).
A building downwash analysis was conducted using the EPA’s BPIP-Prime software. All buildings and structures owned by Kodak at Eastman Business Park were included. The point source stack heights for the boilers were found to be greater than the calculated GEP stack heights; therefore these stacks are not affected by aerodynamic downwash.

2846/BART Analysis 9-29.doc 2-4 Contri bution to Visibility Impairment

### 2.3 CALPOST Processing of Visibility Impacts
The CALPUFF Modeling System postprocessor, CALPOST, was used to generate the visibility impacts from the CALPUFF output. Th e NYSDEC protocol recommends the use of CALPOST Version 6.221 (Method 8, Mode 5) wh ich performs the correct calculations with the latest EPA/FLM recommendations usin g the new IMPROVE equation for extinction coefficient calculations.

The 20% best natural conditions at each Class I area were input to the CALPOST program. The use of these background values is required by the FLMs for NY BART analyses since the FLMs have accepted the use of a single year of meteorological data. These values are location specific; therefore separate CALPOST runs were made for each Class I Area included in the analysis. Results are in Tables 2-4 and 2-5.
Table 2-4 Visibility Impacts (delta deciview) Pr edicted using the VT-NWS Meteorological Data Set

VT-NWS 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) Julian Day hr 0 % SO 4 % NO 3 % OC % EC % PMC % PMF Lye Brook Wilderness Area Boilers 41&42 1 0.798 78 80.60 18.55 0.26 0.13 0.12 0.33 8 0.354 214 96.75 2.77 0.15 0.07 0.06 0.19 Boiler 43 1 0.446 78 76.46 22.29 0.54 0.16 0.15 0.4 8 0.203 329 68.81 29.47 0.73 0.22 0.22 0.55 Package Boilers 1 0.005 78 69.35 29.86 0 0 0.63 0.15 8 0.002 254 79.96 19.23 0 0 0.64 0.17 Acadia National Park Boilers 41&42 1 0.529 225 96.58 3.03 0.13 0.06 0.03 0.16 8 0.402 168 87.70 11.77 0.19 0.09 0.04 0.22 Boiler 43 1 0.291 225 95.57 3.78 0.30 0.09 0.05 0.21 8 0.225 168 84.78 14.36 0.41 0.12 0.05 0.28 Package Boilers 1 0.003 346 70.60 29.18 0 0 0.13 0.1 8 0.002 355 55.75 43.70 0 0 0.32 0.22 Brigantine National Wildlife Refuge Boilers 41&42 1 0.606 238 95.59 3.96 0.16 0.08 0.04 0.18 8 0.252 287 91.71 7.82 0.16 0.08 0.03 0.2 Boiler 43 1 0.323 238 94.12 5.16 0.35 0.10 0.05 0.23 8 0.142 214 97.78 1.47 0.36 0.10 0.05 0.24 Package Boilers 1 0.004 300 61.90 37.14 0 0 0.76 0.21 8 0.002 214 97.82 1.87 0 0 0.24 0.1

2846/BART Analysis 9-29.doc 2-5 Contri bution to Visibility Impairment

### Table 2-4 Visibility Impacts (delta deciview) Pr edicted using the VT-NWS Meteorological Data Set (Continued)

VT-NWS 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) Julian Day hr 0 % SO 4 % NO 3 % OC % EC % PMC % PMF Presidential Range – Dry River Boilers 41&42 1 0.709 252 97.40 2.05 0.18 0.09 0.05 0.23 8 0.306 203 96.73 2.91 0.12 0.06 0.03 0.15 Boiler 43 1 0.39 252 96.44 2.66 0.41 0.12 0.07 0.3 8 0.183 30 69.34 29.34 0.59 0.17 0.12 0.44 Package Boilers 1 0.004 252 96.43 3.12 0 0 0.33 0.12 8 0.002 195 87.69 11.91 0 0 0.29 0.1 Great Gulf Boilers 41&42 1 0.703 252 97.43 2.02 0.18 0.09 0.05 0.22 8 0.307 203 96.62 3.02 0.12 0.06 0.03 0.15 Boiler 43 1 0.386 252 96.48 2.63 0.40 0.12 0.07 0.3 8 0.192 30 69.17 29.51 0.59 0.17 0.12 0.44 Package Boilers 1 0.004 252 96.49 3.08 0 0 0.33 0.12 8 0.002 195 87.77 11.83 0 0 0.29 0.1 Dolly Sods Boilers 41&42 1 0.619 221 95.84 3.49 0.22 0.10 0.08 0.27 8 0.197 348 75.89 23.85 0.09 0.04 0.02 0.11 Boiler 43 1 0.357 221 94.23 4.70 0.49 0.14 0.10 0.35 8 0.119 239 97.62 1.86 0.24 0.07 0.04 0.17 Package Boilers 1 0.004 221 93.79 5.61 0 0 0.46 0.14 8 0.001 348 63.98 35.86 0 0 0.09 0.05 Otter Creek Boilers 41&42 1 0.478 222 96.18 3.33 0.17 0.08 0.05 0.20 8 0.209 348 75.10 24.63 0.10 0.04 0.02 0.12 Boiler 43 1 0.276 297 81.79 17.06 0.53 0.15 0.09 0.38 8 0.120 290 83.17 16.25 0.27 0.08 0.04 0.19 Package Boilers 1 0.003 222 93.88 5.71 0 0 0.30 0.10 8 0.001 348 63.00 36.83 0 0 0.10 0.05

2846/BART Analysis 9-29.doc 2-6 Contri bution to Visibility Impairment

### Table 2-5 Visibility Impacts (delta deciview) Pr edicted using the Hybrid Meteorological Data Set
Hydrid 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) Julian Day hr 0 % SO 4 % NO 3 % OC % EC % PMC % PMF Lye Brook Wilderness Area Boilers 41&42 1 1.166 330 78.01 21.15 0.26 0.13 0.12 0.33 8 0.595 217 95.56 3.79 0.20 0.10 0.08 0.26 Boiler 43 1 0.688 330 73.48 25.27 0.54 0.16 0.15 0.4 8 0.341 290 79.28 19.84 0.40 0.12 0.07 0.3 Package Boilers 1 0.009 330 63.7 35.57 0 0 0.58 0.15 8 0.004 217 93.36 5.99 0 0 0.51 0.14 Acadia National Park Boilers 41&42 1 0.845 18 78.79 20.67 0.18 0.09 0.04 0.22 8 0.321 90 89.01 10.18 0.28 0.13 0.07 0.34 Boiler 43 1 0.472 18 73.93 25.24 0.39 0.11 0.06 0.28 8 0.194 21 72.84 26.02 0.55 0.16 0.06 0.38 Package Boilers 1 0.006 18 64.89 34.79 0 0 0.22 0.1 8 0.002 217 98.51 1.18 0 0 0.21 0.08 Brigantine National Wildlife Refuge Boilers 41&42 1 0.607 330 77.43 21.53 0.36 0.17 0.10 0.42 8 0.276 254 94.69 4.81 0.17 0.08 0.04 0.21 Boiler 43 1 0.369 330 72.96 25.46 0.74 0.21 0.12 0.52 8 0.147 140 88.97 9.77 0.6 0.17 0.08 0.41 Package Boilers 1 0.004 330 63.33 35.99 0 0 0.49 0.18 8 0.002 213 96.87 2.66 0 0 0.33 0.13 Presidential Range – Dry River Boilers 41&42 1 0.874 223 96.11 3.44 0.15 0.07 0.04 0.18 8 0.489 48 79.95 19.19 0.29 0.14 0.08 0.35 Boiler 43 1 0.483 223 94.79 4.46 0.34 0.10 0.06 0.25 8 0.285 48 75.38 23.28 0.61 0.18 0.10 0.45 Package Boilers 1 0.005 340 63.25 36.35 0 0 0.26 0.12 8 0.003 48 66.66 32.80 0 0 0.40 0.15 Great Gulf Boilers 41&42 1 0.847 223 96.11 3.44 0.15 0.07 0.04 0.19 8 0.461 48 79.98 19.17 0.28 0.14 0.08 0.35 Boiler 43 1 0.470 223 94.81 4.45 0.34 0.10 0.06 0.25 8 0.265 309 78.02 21.24 0.34 0.10 0.06 0.25 Package Boilers 1 0.005 340 63.55 36.07 0 0 0.25 0.12 8 0.003 48 66.70 32.75 0 0 0.40 0.15

2846/BART Analysis 9-29.doc 2-7 Contri bution to Visibility Impairment

### Table 2-5 Visibility Impacts (delta deciview) Pr edicted using the Hybrid Meteorological Data Set (Continued)
Hydrid 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) Julian Day hr 0 % SO 4 % NO 3 % OC % EC % PMC % PMF Dolly Sods Boilers 41&42 1 0.763 233 94.00 5.62 0.13 0.06 0.03 0.16 8 0.118 240 94.88 4.71 0.14 0.07 0.03 0.17 Boiler 43 1 0.469 233 92.62 6.74 0.31 0.09 0.04 0.22 8 0.062 240 93.30 6.02 0.32 0.09 0.04 0.23 Package Boilers 1 0.004 233 90.17 9.61 0 0 0.14 0.07 8 0.001 261 94.84 4.87 0 0 0.21 0.06 Otter Creek Boilers 41&42 1 0.646 233 94.31 5.32 0.13 0.06 0.03 0.15 8 0.117 240 94.85 4.74 0.14 0.07 0.03 0.17 Boiler 43 1 0.396 233 93.06 6.31 0.30 0.09 0.04 0.21 8 0.062 240 93.26 6.06 0.32 0.09 0.04 0.23 Package Boilers 1 0.004 233 90.43 9.35 0 0 0.15 0.07 8 0.001 220 91.32 8.06 0 0 0.48 0.16

2846/BART Analysis 9-29.doc 2-8 Contri bution to Visibility Impairment! !

! !

! !

! ! ! !

! ! ! ! ! ! ! ! ! ! ! !

! ! ! ! ! ! Rochester Syracuse

Springfield Worcester Manchester

! ! Pittsburgh 

### PA

NJ NY

MD

DE WV
VA Dolly Sods Wilderness Brigantine Wilderness Lye Brook Wilderness Great Gulf Wilderness

Presidential Range Dry River Wilderness Acadia National Park

Otter Creek Wilderness 

### CT RI MA VT
NH ME

Boston Albany Buffalo

Hartford

New York

Baltimore Providence

Washington Philadelphia Source: Raster and Vector Data, ESRI



### Eastman Business Park BART Analysis Rochester, New York 

# ^ _ Eastman Business Park 

# °

0 30 60 15 Miles



### Figure 2-1 Modeled Class I Areas

## 3.0 CONTROL TECHNOLOGIES

Technically feasible control technologies are described in the document Assessment of Control Technology Options for BART-Eligible Sources , Northeast States for Coordinated Air Use Management (NESCAUM), March 2005 (the NESCAUM Assessment). This Analysis reviews each of the technologies presented in the NESCAUM Assessment in turn. Each technology description from the NESCAUM Assessment is presented in boxes below, followed by an analysis of its applicability to Boilers 41, 42 and 43 at Eastman Business Park. Other control technologies are presented at the end of this section. 

### 3.1 Sulfur Dioxide Control Options

Low-sulfur Coal

Coal with low sulfur content can be burned and meet applicable SO 2 emission standards without the use of additional controls is sometimes referred to as “compliance coal.” Coals naturally low in sulfur content may be mined directly from the ground. Alternatively, th e sulfur content of coal fired in the boiler may belowered first by cleaning the coal or blending coals obtained from several sources. However, burning lowsulfur coal may not be a technically feasible or economically practical SO 2 control alternative for all boilers. In some cases, a coal with the required sulfur content to meet the applicable standard may not be available or cannot be fired satisfactorily in a given boiler unit design. Even if such a coal is available, use of the low-sulfur coal that must be transported long distances from the mine may not be cost competitive with burning higher sulfur coal supplied by closer mines and using a post-combustion control device.


### This control option is not available for Boilers 41, 42 and 43 because the design of the cyclone boilers strictly limits the coal charact eristics. The fusion temperature is a critical criterion for the coal’s ability to combust in the cyclone boilers without causing slagging problems. Similarly, washed coal cannot be used.

Wet FGD Systems

The SO 2 in flue gas can be removed by reacting the sulfur compounds with a solution of water and an alkaline chemical to form insolubl e salts that are removed in the scrubber effluent... Most wet FGD systems for control of SO 2 emissions from coal-fired electric u tility boilers are based on using either limestone or lime as the alkaline source. At some of these facilities, fly ash is mixed with the limestone or lime. Several other scrubber system designs (e.g., so dium carbonate, magnesium oxide, dual alkali) are also used by a small percentage of the total number of boilers.
The basic wet limestone scrubbing process is simple and is the type most widely used for control of SO 2 emissions from coal-fired electric u tility boilers. Limestone sorbent is inexpensive and generally available throughout the United States. In a wet limestone scrubber, the flue gas containing SO 2 is brought into contact with limestone /water slurry. The SO 2 is absorbed into the slurry and reacts with limestone to form an insoluble sludge. The sludge, mostly calcium sulfite hemihydrate and gypsum, is disposed of in a pond specifically constructed for the purpose or is recovered as a salable byproduct.
The wet lime scrubber operates in a similar manner to the wet limestone scrubber. In a wet lime scrubber, flue gas containing SO 2 is contacted with hydrated lime/water slurry; the SO 2 is absorbed into the slurry and reacts with hydrated li me to form an insoluble sludge. The h ydrated lime provides greater alkalinity (higher pH) and reactivity than limestone. However, lime-scrubbing processes require appropriate disposal of large quantities of waste sludge. The SO 2 removal efficiencies of existing wet limestone scrubbers range from 31 to 97 percent, with an average of 78 percent. The SO 2 removal efficiencies of existing wet lime

2846/BART Analysis 9-29.doc 3-1 Techni cally Feasible Control Technologiesscrubbers range from 30 to 95 percent. For both type s of wet scrubbers, operating parameters affecting SO 2 removal efficiency include liquid-to-gas ratio, pH of the scrubbing medium, and the ratio of calcium sorbent to SO 2 . Periodic maintenance is needed because of scaling, erosion, and plugging problems. Recent advancements include the use of additives or design changes to promote SO 2 absorption or to reduce scaling and precipitation problems.


### Wet FGD systems, including wet limestone and wet lime scrubbers, are technically feasible for retrofit on Boilers 41, 42 and 43. Given th e current configuration, the wet FGD system would probably be installed downstream of the existing ESP.
Complicating factors are as follows:

♦ To comply with NESHAP standards as-p roposed, Kodak may need to install activated carbon injection (ACI) for mercury and dioxin control. The presence of activated carbon in the flyash or the scrubbe r waste severely limits disposal options. If activated carbon is injected upstream of the existing ESP, the ash removed by that ESP would no longer be a salable product. Also, the activated carbon may not have the proper residence time to effectively control mercury upstream of the existing ESP. A separate ACI system, with its own fabric filter to collect the carbon, would be needed to ensure compliance.

♦ To comply with NO x 

### RACT standards, Kodak may need to install selective catalytic reduction (SCR). Space constraints may preclude installation of both SCR and a wet FGD system.

Spray Dryer Absorber
A spray dryer absorber (sometimes referred to as wet-dry or semi-dry scrubbers) operates by the same principle as wet lime scrubbing, except that the flue gas is contacted with a fine mist of lime slurry instead of a bulk liquid (as in wet scrubbing). For the spray dryer absorber process, the combustion gas containing SO 2 is contacted with fine spray droplets of hydrated lime slurry in a spray dryer vessel. This vessel is located downstream of the air heater outlet where the gas temperatur es are in the range of 120 to 180 °C (250 to 350 °F). The SO 2 is absorbed in the slurry and reacts w ith the hydrated lime reagent to form solid calcium sulfite and calcium sulfate as in a wet lime sc rubber. The water is evapor ated by the hot flue gas and forms dry, solid particles containing the reacted sulfur. These partic les are entrained in the flue gas, along with fly ash, and are collected in a PM collection device. Most of the SO 2 removal occurs in the spray dryer vessel itself, although some additional SO 2 capture has also been observed in downstream particulate collection devices, especially fabric filters . This process produces dry reaction waste products for easy disposal.
The primary operating parameters affecting SO 2 removal are the calcium-reagen t-to-sulfur stoichiometric ratio and the approach to saturation in the spray dryer. To increase overall sorben t use, the solids collected in the spray dryer and the PM collection device may be recycled. The SO 2 removal efficiencies of existing lime spray dryer systems range from 60 to 95 percent.


### Spray dryer absorbers are technically feasible for retrofit on Boilers 41, 42 and 43. Again, the system would probably be installed downstr eam of the existing ESP. A new fabric filter would be installed downstream of the spray drye r absorber to collect the dry reaction waste products. Similar to wet FGD systems, there may be problems with space constraints if SCR

2846/BART Analysis 9-29.doc 3-2 Techni cally Feasible Control Technologies

### is also required. Activated carbon injection could be installed for NESHAP compliance in conjunction with a spray dryer absorber, but again the waste products would not be saleable.

Dry Injection
For the dry injection process, dry powdered lime (or anot her suitable sorbent) is directly injected into the ductwork upstream of a PM control device. Some systems use spray humidification followed by dry injection. This dry process eliminates the slurry production and handling equipment required for wet scrubbers and spray dryers, and produces dry reaction waste products for easier disposal. The SO 2 is adsorbed and reacts with th e powdered sorbent. The dr y solids are entrained in the combustion gas stream, along with fly ash, and collected by the PM control device. The SO 2 removal efficiencies of existing dry injection systems range from 40 to 60 percent.


### Dry injection is feasible for retrofit on Bo ilers 41, 42 and 43. The existing ESP would remain in-place, with dry injection followed by fabric filtration added downstream. Dry lime injection with ACI followed by fabric filtration would be a logical system to meet the hydrochloric acid, mercury, dioxin, and par ticulate matter limits in the proposed NESHAP rule.
Based on vendor input, Kodak and SDEGS believe dry powdered lime would not achieve more than about 5% SO 2 

### removal for these units. Another suitable sorbent is trona (trisodium hydrogendicarbonate dehydrate), a naturally-occurring mineral. Trona SO 2 

### removal efficiencies can reach as high as 70%, but sorbent quantities and costs are much higher.

Circulating Fluidized-bed Absorber
In the circulating fluidized-bed absorber (CFBA), the flue gas flows upward through a bed of sorbent particles to produce a fluid-like condition in the bed. This condition is obtained by adjusting gas flow rate sufficiently to support the particles, but not carry them out of the system. Character istics of the bed are high heat and mass transfer, because of high mixing rates, and particle-to-gas contact. These conditions allow the CFBA’s bed of sorbent particles to remove a sorbat e from the gas stream with high effectiveness. In a CFBA, material is withdrawn from the bed for treatment (such as desorption) then re-injected into the bed. The SO 2 removal efficiencies for CFBA technologies range from 80 to 98 percent, providing a very effective means of control.


### For this retrofit application, CF BA would likely achieve similar SO 2 

### removal to a wet FGD system or spray dryer absorber. Since a CF BA is more complicated with less operating history, it is not considered further. 

### 3.2 Nitrogen Oxides Control Options

Combustion Controls
A variety of combustion control practices can be used including low-NO x burners (LNBs), overfire air, offstoichiometric firing, selective or biased burner firing, reburning, and burners-out-of-service. Control of NO x also can be achieved through staged combustion (als o called air staging). With staged combustion, the primary combustion zone is fired with most of the air needed for complete combustion of the coal. The remaining air is introduced into the products of the partial combustion in a secondary combustion zone. Air

2846/BART Analysis 9-29.doc 3-3 Techni cally Feasible Control Technologiesstaging lowers the peak flame temperature, thereby reducing thermal NO x , and lowering the production of fuel NO x by reducing the oxygen available for combination with the fuel nitrogen. Staged combustion may be achieved through methods that require modifying equipment or operating conditions so that a fuel-rich condition exists near the burners (e.g., using specially designed low- NO x burners, selectively removing burners from service, or diverting a portion of the combustion air). In cyclone boilers and some other wet bottom designs, combustion occurs with a molten ash layer and the combustion gases flow to the main furnace; this design precludes the use of low NO x burners and air staging. Low-NO x burners may be used to lower NO x emissions by about 25 to 55 percent. Use of overfire air (OFA) as a single NO x control technique reduces NO x by 15 to 50 percent. When OFA is combined with low- NO x burners, reductions of up to 60 percent may result. The actual NO x reduction achieved with a given combustion control technique may vary from boiler to boiler.
Just as the combustion air to the primary combustion zone can be reduced, part of the fuel may be diverted to create a secondary flame with fuel-rich conditions downstream of the primary combustion zone. This combustion technique is termed reburning and involves injecting 10 to 20 percent of the fuel after the primary combustion zone and completing the combustion with overfire air. The fu el injected downstream may not necessarily be the same as that used in the prim ary combustion zone. In most applications of reburning, the primary fuel is coal and the reburn fuel is natural gas (methane), and the technology is known as “gas reburn.” Other ways to reduce NO x formation by reducing peak flame temperature include using flue gas recirculation (FGR), reducing boiler load, injecting steam or water into the primary combustion zone, and increasing spacing between burners. By using FGR to return part of the flue gas to the primary combustion zone, the fl ame temperature and the concentr ation of oxygen in the primary combustion zone are reduced. Increasing the space betwee n burners provides greater heat transfer to heatabsorbing surfaces. Another combusti on control technique involves reduci ng the boiler load. In this case, the formation of thermal NO x generally decreases directly with decr eases in heat release rate; however, reducing the load may cause po or air and fuel mixing and increase CO and soot emissions.


### Boilers 41, 42 and 43 already use combustion co ntrols to the extent feasible. These boilers are cyclone boilers, which “precludes the use of low-NO x 

### burners and air staging.” Natural gas is already being used as a reburn fuel to reduce NO x 

### emissions.

Selective Catalytic Reduction
The selective catalytic reduction (SCR) process uses a catalyst with ammonia gas (NH3) to reduce the NO and NO 2 in the flue gas to molecular nitrogen and water. The ammonia gas is diluted with air or steam, and this mixture is injected into the flue gas upstream of a metal catalyst bed (composed of vanadium, titanium, platinum, or zeolite). In the reactor, the reduction r eactions occur at the catalyst surface. Typically some ammonia exits the catalyst, on the order of 1-5 ppm in the flue gas; this is called “ammonia slip”. The SCR catalyst bed reactor is usually located between th e economizer outlet and air heater inlet, where temperatures range from 230 to 400 °C (450 to 750 °F). The catalyst modules take up a considerable amount of space; in addition ductwork must be adde d for the ammonia injectio n section. There is not always room in an existing boiler to retrofit an SCR system. As a consequence, fan capacity may have to be increased, owing to the incremental pressure drop from the SCR and as sociated ductwork. In some cases, the boiler must be modified to increase the economi zer exit temperature to th e minimum and/or the air preheater must be modified. Installation of an SCR on a boiler is site specific and this results in a range of capital costs for SCR systems on boilers. SCR catalysts in coal- and oil-fired boilers oxidize a small fraction of the SO 2 in the flue gas to produce SO 3 . The SO 3 in the flue gas from an SCR may only be on the order of 10 ppm (depending on the sulfur-content of the fuel), but it can have impacts on the downstream equipment and emissions. The combinati on of ammonia slip and increased SO 3 can form deposits of ammonium bisulfate in the air preheater . SO can condense in the flue gas in the form of a fine aerosol of sulfuric acid, which can cause a visi ble plume, the so-called “blue plume”.


### Selective catalytic reduction is technically feas ible for Boilers 41, 42 and 43. Complicating factors are as follows:

2846/BART Analysis 9-29.doc 3-4 Techni cally Feasible Control Technologies

### Significant boiler modifications may be need ed for SCR to operate in the correct temperature window.

The SO 2 

### to SO 3 

### conversion could cause significant corrosion and sulfuric acid emission issues.
Ammonia handling introduces a new safety risk.

Selective Noncatalytic Reduction
The selective noncatalytic reduction (SNCR) process is based on the same basic chemistry of reducing the NO and NO 2 in the flue gas to molecular nitrogen and water but does not require the use of a catalyst to prompt these reactions. Instead, the re ducing agent is injected into the fl ue gas stream at a point where the flue gas temperature is within a very specific te mperature range. Currently, two SNCR processes are commercially available: the THERMAL DeNO x and the NO x OUT (USEPA, 1998). The THERMAL DeNO x uses ammonia gas as the reagent and requires the gas be injected where the flue gas temperature is in the range of 870 to 1090 °C (1,600 to 2,000 °F). Consequently, the ammonia gas is injected at a location upstream of the economizer. However, if the ammonia is injected above 1,090 °C (2,000 oF), the ammonia will oxidize and will result in the formation of excess NO x emissions. Once the flue gas temperature drops below the optimum temperature range, the effectiveness of the process drops significantly. By adding hydrogen gas or other chemical enhancers, the reduction reactions can be sustained to temperatures down to approximately 700 °C (1,300 °F). The NO x OUT is a similar process but uses an aqueous urea solution as the reagent in place of ammonia. Us ing nitrogen-based reagents requi res operators of SNCR systems to closely monitor and control the rate of reagent injection. If injection rates are too high, NO x emissions may increase, and stack emissions of amm onia in the range of 10 to 50 ppm may also result. A portion (usually around 5 percent) of the NO reduction by SNCR systems results from transformation of NO to N2O, which is a global warming gas.


### The effectiveness of SNCR is very boiler-spec ific, and its effectiveness on Boilers 41, 42 and 43 is unknown. For the purposes of this Assessment, we assume that SNCR can be retrofitted on the boilers with mo derate effectiveness. The SNCR retrofit would have the same ammonia safety and ammonia salts probl ems as the SCR system discussed above. 

### 3.3 Particulate Matter Control Options

Electrostatic Precipitators
Electrostatic precipitator (ESP) control devices have been used to control PM emissions for over 80 years. These devices can be designed to achieve high PM coll ection efficiencies (greater than 99 percent), but at the cost of increased unit size. An ESP operates by impa rting an electrical charge to incoming particles, and then attracting the particles to oppositely charged meta l plates for collection. Periodically, the particles collected on the plates are dislodged in sheets or agglomerates (by rapping the plates) and fall into a collection hopper. The dust collected in the ESP hopper is a solid waste that must be disposed of.
The effectiveness of particle capture in an ESP depend s largely on the electrical resistance of the particles being collected. An optimum value exists for a given ash. Above and below this value, particles become less effectively charged and collected... Coal that contains a moderate to high amount of sulfur (more than approximately three percent) produces an easily collected fly ash. Lo w-sulfur coal produces a highresistivity fly ash that is more difficult to collect. Resistivity of the fly ash can be changed by operating the boiler at a different temperature or by conditioning the particles upstream of the ESP with sulfur trioxide, sulfuric acid, water, sodium, or ammonia. In addition, collection efficiency is not uniform for all particle

2846/BART Analysis 9-29.doc 3-5 Techni cally Feasible Control Technologiessizes. For coal fly ash, particles larger than about 1 to 8 mm and smaller than about 0.3 mm (as opposed to total PM) are typically collected with efficiencies from 95 to 99.9 percent. Particles near the 0.3 mm size are in a poor charging region that reduces collection effici ency to 80 to 95 percent.

An ESP can be used at one of two locations in a co al-fired electric utility boile r system. For many years, every ESP was installed downstream of the air heater where the temperatur e of the flue gas is between 130 and 180 °C (270 and 350 °F). An ESP installed at this location is referred is as a "cold-side" ESP. However, to meet SO 2 emission requirements, many electric utilities switched to burning low-sulfur coal (discussed in Section 2.3.2 under SO 2 controls). These coals have higher electrical ash resistivities, making the fly ash more difficult to capture downstream of the air heater . Therefore, to take advantage of the lower fly-ash resistivities at higher temperatures, some ESPs ar e installed upstream of the air heater, where the temperature of the flue gas is in the range of 315 to 400 °C (600 to 750 °F). An ESP installed upstream of the air heater is referred to as a "hot-side" ESP.


### Boilers 41, 42 and 43 have ESPs currently installe d. The control options being considered involve maintaining those existing ESPs in-s ervice. Due to location and breeching configuration there is not enough space to allo w for the addition of collection fields to the existing ESPs for Boilers 41, 42 and 43.

Fabric Filters
Fabric filters (FF) have been used for fly ash c ontrol from coal-fired electric utility boilers for about 30 years. This type of control device collects fly ash in the combustion gas stream by passing the gases through a porous fabric material. The buildup of solid particles on the fabric su rface forms a thin, porous layer of solids or a filter, which further acts as a filtration medium. Gases pass through this cake/fabric filter, but the fly ash is tr apped on the cake surface. Th e fabric material used is typically fabricated in the shape of long, cylindrical bags. Hence, fabric filte rs also are frequ ently referred to as "baghouses."
Gas flow through a FF becomes excessively restricted if the filter cake on the bags becomes too thick. Therefore, the dust collected on the bags must be removed periodically. The type of mechanism used to remove the filter cake classifies FF design types. Depending on the FF design type, the dust particles will be collected either on the inside or outside of the bag. For designs in which the dust is collected on the inside of the bags, the dust is removed by either mechanically shaking the bag (called a "shaker type" FF) or by blowing air through the bag from the opposite side (called a "reverse-air" FF). An alternate design mounts the bags over internal frame structures, called "cages" to allow collection of the dust on the outside of the bags. A pulsed jet of compressed air is used to cause a sudden stretching then contraction of the bag fabric dislodging the filter cake from the bag. This de sign is referred to as a "pulse-jet" FF. The dislodged dust particles fall into a hopper at the bottom of the baghouse. The dust collected in the hopper is a solid waste that must be disposed of.
An FF must be designed and operated carefully to ensure that the bags inside the collector are not damaged or destroyed by adverse operating conditions. The fabric material must be compatible with the gas stream temperatures and chemical composition. Because of the temperature limitations of the available bag fabrics, location of an FF for use in a coal-fired electric utility boile r is restricted to downstream of the air heater. In general, fabric filtration is the best commercially available PM control technology for high-efficiency collection of small particles.
Electrostatic stimulation of fabric filtration (ESFF) invo lves a modified fabric filter that uses electrostatic charging of incoming dust particles to increase collecti on efficiency and reduce pre ssure drop compared to fabric filters without charging. Filter bags are specia lly made to include wires or conductive threads, which produce an electrical fi eld parallel to the fabric surface. Conductors can also be placed as a single wire in the center of the bag. When the bags are mounted in the baghouse, the conductors are attached to a wiring harness that supplies electricity. As particles enter th e field and are charged, th ey form a porous mass or cake of agglomerates at the fabric surface. Greater porosity of the cake reduces pressure drop, while the

2846/BART Analysis 9-29.doc 3-6 Techni cally Feasible Control Technologies2846/BART Analysis 9-29.doc 3-7 Techni cally Feasible Control Technologies agglomeration increases efficiency of small partic le collection. Cleaning is required less frequently, resulting in longer bag life. For fe lted or nonwoven bags, the field prom otes collection on the outer surface of the fabric, which also promotes longer bag life. Filtr ation velocity can be increased so that less fabric area is required in the baghouse. The amount of re duction is based on an economic balance among desired performance, capital cost, and operating costs. A number of variations exist on the ESFF idea of combining particle charging with fabric filtration.


### Fabric filtration is technically feasible for Bo ilers 41, 42 and 43. While fabric filters are effective in removing filterable particulate, the BART analysis includes both filterable and condensable particulate; fabric filters are generally ineffective in controlling condensable particulate.
Fabric filtration is being considered as part of a multi-pollutant control approach. Specifically, a fabric filter downstream of a dr y injection system (or spray dryer absorber) that includes ACI could control SO 2 

### , mercury, dioxin, acid gas, and particulate.
Electrostatic stimulation of fabric filtration is not considered as a separate control option because effectiveness and costs would be sim ilar to fabric filtration, and an ESFF system would be more complicated.

Particle Scrubbers and Mechanical Collectors
Particle scrubbers are generally much less efficient than ESPs and baghouses (especially in collecting finer fraction of PM). For this reason and because they en tail higher operating costs associated with achieving high collection efficiency, they are not widely used in the industry. Si milarly, mechanical collectors have the least collection efficiency and are hardly used in the industry. These two methods are not discussed further in this report.



### Particle scrubbers and mechanical collectors are not considered because essentially any particulate that would be caught is already being caught by the existing ESPs. 

### 3.4 Other Control Options
Kodak and SDEGS are considering an operatin g restriction where only two of the three coal-fired cyclone boilers would operate at an y one time (the Restricted Operation case). This would result in approximately one-third reduction of SO 2 

### , NO x 

### , and particulate matter when compared to the fu ll load case. To be feasible, such a restriction would need to allow one boiler to ramp up while another is shuttin g down, and it would need to allow periods of three-boiler operation for scheduled and unscheduled outages of Boiler 44.
Note that the federal rule says “it is not our inte nt to direct States to switch fuel forms, e.g. from coal to gas.” Therefore this Analysis does not include fuel switching as a control option.
Based on a review of available documents, we believe the potentially applicable retrofit control technologies presented in this Analys is represent the full range of demonstrated alternatives.

## 4.0 CONTROL EFFECTIVENESS

As shown in the last section, the list of feasible additional control technologies includes:

1) Restricted operation: reduction of SO 2 

### , NO x

### , and particulate matter by about onethird;.

2) Lime dry injection: reduction of SO 2 

### by 5%;

3) Trona dry injection: reduction of SO 2 

### by 70%;

4) Spray dryer absorber: reduction of SO 2 

### by 90%;

5) Wet flue gas desulfurization: reduction of SO 2 

### by 90%;

6) Selective non-catalytic reduction: reduction of NO x 

### by 35%;

7) Selective catalytic reduction: reduction of NO x 

### by 70%; and

8) Fabric filtration: reduction of the filterable portion of particulate matter to 0.02 pounds per million Btu.
Some technologies will provid e some collateral control of other pollutants; for example, SO 2 

### control technologies can also remove some pa rticulate matter. Because that level of control is difficult to predict and generally not subject to vendor guarantee or permit limit, such emission reductions are not included in this Analysis.

2846/BART Analysis 9-29.doc 4-1 Control Effectiveness2846/BART Analysis 9-29.doc 5-1 Five-Factor Analysis 

## 5.0 FIVE-FACTOR ANALYSIS
5.1 Costs of Compliance
Control costs are evaluated using the tec hniques in the EPA Control Cost Manual as recommended in 40 CFR 51 Appendix Y, supplemented by vendor data for SO 2 

### and PM control options, and supplemented by Kodak a nd SDEGS knowledge of site-specific issues and costs.
Per the federal rule, baseline emissions are “anticipated annual emissions based upon actual emissions from a baseline period. 2 

### ” Calendar years 2007-2009 are selected as the baseline. Boiler operations were significan tly different prior to 2007 (with three other large boilers operating onsite), so the most recent three yea r period was selected as representative.
Average cost of control is calculated per the federal regulation as follows:

Annualized cost of control (Baseline emission rate – controlled emission rate)
Per the federal regulation we also calculate th e incremental cost of control, comparing costs to the restricted operation case. For this analysis we use the Restricted Operation emission rate instead of the baseline emission ra te when calculating the tons removed:

Annualized cost of control (Restricted Operation emission rate – controlled emission rate)
The baseline and Restricted Operation emissi on rates are shown in Table 5-1, and the control costs are summarized in Table 5-2.
Table 5-1 Baseline & Restricted Operation Emission Rate

Precursor Baseline Emissions, ton/year Re stricted Operation Emissions, ton/year
SO 2 

### 11,998 9,843 NO x 

### 2,449 1,969 Particulate matter* 619 544 * includes filterable and condensable particulate matter.

2 Note that the baseline for cost estimation is different fr om the baseline for modeling; per NYSDEC guidance, baseline modeling uses the highest actual 24-hour aver age emission rate in the last five years.

### Table 5-2 Summary of Control Costs

Technology Annualized Cost of Control Average Cost of Control ($/ton) Incremental Cost of Control ($/ton) $8,732 SO 2 $9,947 SO 2 Dry lime injection & fabric filtration $5,238,187 $10,578 PM $11,255 PM $3,487 SO 2 $3,545 SO 2 Dry trona injection & fabric filtration $29,286,852 $107,530 PM $102,104 PM $1,406 SO 2 $1,597 SO 2 Spray dryer absorber & fabric filtration $15,184,149 $55,750 PM $59,135 PM $1,482 SO 2 $1,745 SO 2 Wet FGD & fabric filtration $16,006,954 $58,771 PM $64,614 PM SNCR $1,817,144 $2,120 NO x $2,564 NO x SCR $3,780,977 $2,206 NO x $2,688 NO x


### Supporting calculations are presented in Appendi x A. Regarding the cost calculations, there has been no preliminary layout and sizing of equipment to determine how the system would be configured and the fin al real estate required, and whether there is sufficient construction laydown space. There could be space constraints not accounted for here, especially if multiple layers of control are required. 

### 5.2 Energy & Non-Air Quality Environmental Impacts
The energy and non-air quality impacts for the remaining alternatives are presented in Table 5-3. Table 5-3 Energy & Non-Air Quality Environmental Impacts

Process Electricity Use Solid Waste generation Other impacts Dry lime injection & fabric filtration 184 kW 8,400 tons/yr
Dry trona injection & fabric filtration 184 kW 107,600 tons/yr
Spray dryer absorber & fabric filtration 1103 kW 43,000 tons/yr Upstream impacts associated with sorbent mining & transport.

Wet FGD & fabric filtration 551 kW 26,600 tons/yr 117 million gallons wastewater/year. May need settling ponds for wastewater treatment. Upstream impacts associated with sorbent mining & transport. SNCR 38 kW SCR 591 kW Catalyst disposal Ammonia needs to be used in some form. This adds a new bulk chemical with risk management requirements. Ammonia accumulation in the ash may prevent its beneficial reuse. If reheat is needed for SCR, that will require additional natural gas use. Ammonia slip emissions can increase particulate matter secondary generation.

2846/BART Analysis 9-29.doc 5-2 Five-Factor Analysis

### Any material that needs to be transported in or out of the site will have transportation impacts, including possibly issues with neig hbors and the New York State Department of Transportation. 

### 5.3 Existing Pollution Control Technology
41, 42 and 43 Boilers use electrostatic precipitators to control particulate matter, and natural gas reburn to control NOx. 

### 5.4 Remaining Useful Life of the Source
The remaining useful life of the cyclone boilers has not been determined. Cost effectiveness calculations use the standard equipment life in the OAQPS Control Cost Manual. Changes to Kodak and tenant operations at Eastman Business Park could change the steam needs and decrease the useful life of these boilers, and other pending environmental regulations could also decrease their useful life. 

### 5.5 Degree of Visibility Improvement
This report presents CALPUFF modeling results for multi-pollutant control strategies to evaluate options for a single retrofit projec t that addresses BART, RACT, and NESHAP compliance. Therefore, in addition to the rest ricted operation case the model cases in this analysis include the followi ng retrofit combinations:
SCR, lime dry injection, and fabric filtration; and
SCR, spray dryer absorber, and fabric filtration.
The results of the visibility modeling analysis ar e presented in detail in Section 6, below. Comparing to the maximum 98 th 

### percentile visibility impacts (at Lye Brook Wilderness using the hybrid data set), cost effectiveness in annualized dollars per deciview is calculated by dividing the annualized control costs (pre sented in Table 5-2) by the improvement in deciviews. Results are shown in Table 5-4.
Table 5-4 Visibility Improvement Cost-Effectiveness

Technology Combination Modeled impact, ddv

Baseline 0.903

Restricted Operation 0.697 Annualized Cost of Control Baseline, $/yr/ddv Incremental, $/yr/ddv SCR, dry lime injection, fabric filter 0.812 $8,476,529 $93,148,675 - SCR, spray dryer absorber, fabric filter 0.165 $18,422,491 $24,962,725 $34,628,743

2846/BART Analysis 9-29.doc 5-3 Five-Factor Analysis2846/BART Analysis 9-29.doc 5-4 Five-Factor Analysis 

### Following NYSDEC guidance, baseline emissions for modeling use the highest 24-hr actual emission rates in the last five years; for consistency with this approach the post-control scenarios are based on emission reductions from that baseline. This approach over-predicts actual visibility impacts, and actual visibili ty improvements, and therefore under-predicts the dollars-per-deciview cost of control.

## 6.0 VISIBILITY ANALYSIS

This section presents the CALPUFF visibility m odeling analysis to demonstrate the expected net improvement in visibility fo r the selected pollution control options at each of the seven Class I areas.


### 6.1 Emission Rate Calculations
Baseline emissions are calculated as presented in Section 2.1, above. For the control options, the control efficiencies presented in Section 4 are applied to the baseline emissions. The Restricted Operating case em issions are conservatively calculated based on shutting off the least-polluting of the three cyclone boilers for e ach pollutant. For particulate matter, fabric filter control efficienc y is weighted towards coarse particulate, as fabric filters are more effective in removi ng coarse particles than fine particles. 

### 6.2 CALPUFF Modeling
The baseline modeling presented in Section 2 serves as the base case scenario. The modeling follows the NYSDEC Guidance and Protocol fo r Visibility Modeling of BART Eligible Sources (dated February 25, 2010).
The protocol requires two meteorological data sets to be used in the modeling. Although both data sets are for the 2002 period, NYSDEC recommends that both be used for BART analysis to “envelope the set of meteorological conditions which could lead to the maximum impacts even with the same data year”..
As required by the NYSDEC, visibility impacts are assessed in the following Class I areas: Lye Brook Wilderness Area in VT, Acadia Nati onal Park in ME, Brig antine Wildlife Refuge in NJ, Presidential Range and Great Gulf Wilder ness Areas in NH, and Dolly Sods and Otter Creek Wilderness Areas in WV.
The CALPUFF net visibility modeling was run in cluding Boilers 41, 42, 43 and the four oilfired package boilers at Eastman Business Park using maximum daily emission rates of SO 2 

### , NO x 

### and PM. 

### 6.3 CALPOST Processing of Visibility Impacts
The CALPUFF Modeling System postprocessor, CALPOST, was used to generate the visibility impacts from the CALPUFF outpu t. The FLMs have reco mmended the use of CALPOST Version 6.221 (Method 8, Mode 5) wh ich performs the correct calculations with the latest EPA/FLM recommendations usin g the new IMPROVE equation for extinction coefficient calculations.

2846/BART Analysis 9-29.doc 6-1 Visibility Analysis

### The 20% best natural conditions at each Class I area was input to the CALPOST program. The use of these background values is required by the FLMs for NYSDEC BART analyses since they have accepted the use of a si ngle year of meteorological data.
The analysis follows the NYSDEC recommend ation for CALPUFF post-processing of specific visibility impacts to assist in their determin ation of the best BART alternative for each source, namely:

1) the maximum and 98% (or 8th highest) 24 hou r visibility impact for the pre- and post-BART control source emissions for each alternative;

2) the number of days and the corresponding magnitude of visibility impacts which exceed a deciview value of 0.1, 0.5 a nd 1.0 for the pre- and post-BART control source emissions for each alternative; and

3) for facilities with more than one BART eligible unit, the cumulative visibility maximum impacts of all non-exempt units.
The presented impacts show th e individual contribution of SO x 

### , NO x 

### and particulate emissions.


### 6.4 CALPUFF/CALPOST Results
The NYSDEC guidance states CALPUFF impact calculations must use the same scheme for the pre and post control scenarios in all these calculations. The hybrid scheme was used, since it has the highest 98% 24 hour visibility impact. Table 6-1 below shows the maximum and 98% 24 hour visibility impact for the baseline case using the hybrid data set at Lye Brook. Table 6-2 compares the maximum and 98% (or 8t h highest) 24 hour visibility impact for the pre- and post-BART control source emissions for each alternative. Table 6-3 shows the number of days and the correspo nding magnitude of visibility impacts which exceed a deciview value of 0.1, 0.5 and 1. 0 for the pre- and post-BART control source emissions for each alternative.

2846/BART Analysis 9-29.doc 6-2 Visibility Analysis

### Table 6-1 Maximum and 98% 24 hr Visibility Impact, Base Case

Hybrid 2002 % of Modeled Extinction by Species Julian

Day Rank Change in Vis (ddv) hr 0 %_SO 4 %_NO 3 %_OC %_EC %_PMC %_PMF Lye Brook Wilderness Area All 1 1.793 330 76.35 22.66 0.36 0.14 0.13 0.36 8 0.903 217 95.07 4.15 0.29 0.11 0.10 0.29 Boilers 41& 42 1 1.166 330 78.01 21.15 0.26 0.13 0.12 0.33 8 0.595 217 95.56 3.79 0.20 0.10 0.08 0.26 Boiler 43 1 0.688 330 73.48 25.27 0.54 0.16 0.15 0.4 8 0.341 290 79.28 19.84 0.40 0.12 0.07 0.3



### Table 6-2 Visibility Impact fo r Pre- and Post-BART Control

Change in Visibility (ddv) Lye Brook Wilderness Area

Rank Baseline Restricted SCR, dry lime injection, fabric filter SCR, spray dryer absorber,

fabric filter All 1 1.793 1.380 1.478 0.392 8 0.903 0.697 0.812 0.165 Boilers 41& 42 1 1.166 0.728 0.958 0.224 8 0.595 0.382 0.548 0.089 Boiler 43 1 0.688 0.688 0.558 0.163 8 0.341 0.341 0.292 0.073

2846/BART Analysis 9-29.doc 6-3 Visibility Analysis2846/BART Analysis 9-29.doc 6-4 Visibility Analysis 

### Table 6-3 Number of Days Exceedi ng 0.1, 0.5, and 1.0 Deciview

Operating Scenario # of Days with Change in Vis

=>0.1 ddv # of Days with Change in Vis

=>0.5 ddv # of Days with Change in Vis

=>1.0 ddv Maximum Change in Vis (ddv) Lye Brook Wilderness Area Base Case All (B 41,42,43 & PB1-4) 113 24 6 1.793 Boilers 41 & 42 85 11 1 1.166 Boiler 43 44 5 0 0.688 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 94 15 4 1.380 Boilers 41 & 42 49 3 0 0.728 Boiler 43 44 5 0 0.688 SCR & Lime DSI All (B 41,42,43 & PB1-4) 104 21 5 1.478 Boilers 41 & 42 72 9 0 0.958 Boiler 43 34 1 0 0.558 SCR & SDA All (B 41,42,43 & PB1-4) 24 0 0 0.392 Boilers 41 & 42 7 0 0 0.224 Boiler 43 3 0 0 0.163



### Complete CALPUFF result data tables are included in Appendix B.2846/BART Analysis 9-29.doc 7-1 Best Emission Control Option 

## 7.0 BEST EMISSION CONTROL OPTION

Kodak and SDEGS propose the Restricted Opera ting as the best emission control option for Boilers 41, 42 and 43. This is based on the options evaluated, the average and incremental costs of each option; the energy and non-air quality environmental impacts of each option; the remaining useful life of the source; and the modeled visibility impacts.
NYSDEC has the authority to determine that the Restricted Option is the best emission control option based on the following:

♦ Boilers 41, 42 and 43 are each much sma ller than the equivale nt of 200 MW, and therefore the presumptive BART limits in the federal rule do not apply.

♦ The federal guidance states “there may be cases where the installation of controls would affect the viability of continued plant operations.” and “There may be unusual circumstances that justify taking into consideration the conditions of the plant and the economic effects of requiring the use of a given control technology. These effects would include effects on pr oduct prices, the market share, and profitability of the source.” Kodak and SD EGS can review with NYSDEC the effect of the installation of controls on the viability of Eastman Business Park as a continued major employer in Rochester.

♦ Again per the federal rule, a visibility change of 0.5 deciview is “barely perceptible.” The incremental change from the Restricted Operation case to the top level of control would only create a visi bility change of 0.5 deciview if the 98 th 

### percentile worst-case meteorology happened at the same day as each boiler emitted each individual pollutant at its worst-cas e emission rate, and on a day with top 20% background visibility conditions. This combin ation of events is very unlikely to ever happen. Even if it did, a perceptible visib ility change is only predicted at one Class I area, using one of the two data sets. Therefore, installing control is unlikely to create a perceptible visibility change at any Class I area.

♦ Prior BART assessment results have required controls that were much more costeffective. Examples include 3 

### :

o Omaha Public Power District (OPPD) Nebr aska City Station Unit #1: BART is $136/ton, $4,600,000/yr/deciview;

o Nebraska Public Power District (NPPD) Gerald Gentleman Station Units 1 and 2: BART is $198/ton, $4,200,000/yr/deciview.

3 http://www.deq.state.ne.us/AirDivis.nsf/Pages/Haze2846/BART Analysis 9-29.doc 7-2 Best Emission Control Option 

### ♦ The cost threshold of $5,500 discussed in the New York notice of adoption is not inline with other agencies. For example, in issuing the determinations discussed above, the Nebraska Department of Enviro nmental Quality rejected control options in the $1000-$3000/ton range.
Given the backdrop of upcoming RACT and NESHAP rules, the Restricted Option case allows assurance that Boilers 41, 42, and 43 are unlikely to have a perceptible visibility impact on Class I areas, while retaining flexibility to respond to future requirements. Kodak and SDEGS look forward to NYSDEC’s revi ew, and to discussing BART further.

## Appendix A Supporting CalculationsKODAK PARK BART Control Cost Summary aj/Epsilon 9/26/10

Precursor Baseline Emissions, ton/year
SO2 11998 NOx 2449 Particulate matter* 619 * includes filterable and condensable particulate matter.

Technology A nnua li ze d C os t o f Control $8,732 / ton SO2 $9,947 / ton SO2 $10 ,57 8 / ton PM $11
, 2 55 / ton PM $3,487 / ton SO2 $3,545 / ton SO2 $10 7,5 30 / ton PM $102
, 104 / ton PM $1,406 / ton SO2 $1,597 / ton SO2 $ 55,75 0 / ton PM $ 5 9
, 13 5 / ton PM $1,482 / ton SO2 $1,745 / ton SO2 $ 5 8 ,77 1 / ton PM $64
, 614 / ton PM SNCR $1
, 81 7, 144 $2
, 120 / ton NO x $2 ,5 64 / ton NO x SCR $3 ,7 80
, 9 77 $2
, 206 / ton NO x $2
, 688 / ton NO x

Visibility analysi s

Technology Combination M o d e l e d i mpac t , ddv

Visibility impacts in deciview (ddv) are at Lye Brook, 98th percentile, using the hybrid data set (SCR costs do not include balanced draft conversion, ID fan, electric upgrade to avoid double-counting) Baseline, $/yr/ddv Incremental, $/yr/ddv

$93,148,675
$24,962,725 - $34,628,743 SCR, dry lime injection, fabric filter $8,476,529 SCR, spray dryer absorber, fabric filter $18,422,491 0.812

0.165 Baseline
Restricted Operation A nnualized Cost of Control 0.903

0.697 Dry lime injection & fabric filtration $5,238,187 Dry trona injection & fabric filtration $29,286,852 Spray dryer absorber & fabric filtration $15,184,149
Wet FGD & fabric filtration $16,006,954 Average Cost of Control Incremental Cost of Control Restricted Operation Emissions, ton/year
9843 1969

544Kodak ParkControl Cost Analysis9/26/2010System operation5397 5397 5397 5397 hours/year507,714 507,714 507,714 507,714 ACFM airflowDirect CostsPurchased Equipment Cost $2,100,000 $2,100,000 $4,800,000 $8,200,000 Boiler 41 & 42 modifications (vendor quote)$1,250,000 $1,250,000 $3,900,000 $6,500,000 Boiler 43 modifications (vendor quote)$1,100,000 $3,100,000 $1,300,000 $1,800,000 reagent handling system (vendor quote)$1,610,000 $1,610,000 $1,610,000 $1,610,000 conversion to balanced draft (vendor quote)$1,868,000 $1,868,000 $1,868,000 $1,868,000 ID fans (W Fleming email 8-30)$50,000 $50,000 $7,146,342 $7,146,342 ductwork (truss bridge for SDA & WFGD; W Fleming 9-13 email)$0 $0 $475,899 $475,899 New electric utility bus (double-ended load center)(W Fleming 9-13 email)$482,182 $482,182 $482,182 $482,182 Stack liner (Pennguard Block, W Fleming 9-13 email)$40,000 $40,000 $40,000 $40,000 SO2 emission monitor (consultant estimate)$0 $0 $0 $215,872 wastewater pretreatment & sludge thickening (EPA CUECost model)$8,500,182 $10,500,182 $21,622,423 $28,338,295 equipment capital cost (sum of above)Instrumentation 0.1 $850,018 0.1 $1,050,018 0.1 $2,162,242 0.1 $2,833,830 OAQPS Section 6 Table 2.8Sales Taxes 0 $0 0 $0 0 $0 0 $0 tax exempt per http://www.tax.state.ny.us/pdf/current_forms/st/st121_fill_in.pdfFreight 0.05 $425,009 0.05 $525,009 0.05 $1,081,121 0.05 $1,416,915 OAQPS Section 6 Table 2.8Total Purchased Equipment Cost, PEC$9,775,209 $12,075,209 $24,865,787 $32,589,040Direct Installation CostsFoundations and supports 0.06 $586,513 0.06 $724,513 0.06 $1,491,947 0.06 $1,955,342 OAQPS Section 6 Table 2.8Handling and erection 0.4 $3,910,084 0.4 $4,830,084 0.4 $9,946,315 0.4 $13,035,616 OAQPS Section 6 Table 2.8Electrical 0.01 $97,752 0.01 $120,752 0.01 $248,658 0.01 $325,890 OAQPS Section 6 Table 2.8Piping 0.05 $488,760 0.05 $603,760 0.05 $1,243,289 0.05 $1,629,452 OAQPS Section 6 Table 2.8Insulation for ductwork 0.03 $293,256 0.03 $362,256 0.03 $745,974 0.03 $977,671 OAQPS Section 6 Table 2.8Painting 0.01 $97,752 0.01 $120,752 0.01 $248,658 0.01 $325,890 OAQPS Section 6 Table 2.8Total Direct Installation cost$5,474,117 $6,762,117 $13,924,841 $18,249,862Site preparation $0 $0 $0 $0Buildings $0 $0 $0 $0Initial Reagent $52,416 $1,257,984 $178,644 $72,518 two weeks' worth per costs belowTotal Direct Cost, DC $15,301,742 $20,095,310 $38,969,272 $50,911,420Indirect Costs - InstallationEngineering 0.1 $977,521 0.1 $1,207,521 0.1 $2,486,579 0.1 $3,258,904 OAQPS Section 6 Table 2.8Construction and field expenses 0.1 $977,521 0.1 $1,207,521 0.1 $2,486,579 0.1 $3,258,904 OAQPS Section 6 Table 2.8Contractor fees 0.1 $977,521 0.1 $1,207,521 0.1 $2,486,579 0.1 $3,258,904 OAQPS Section 6 Table 2.8Start-up 0.01 $97,752 0.01 $120,752 0.01 $248,658 0.01 $325,890 OAQPS Section 6 Table 2.8Performance test 0.01 $97,752 0.01 $120,752 0.01 $248,658 0.01 $325,890 OAQPS Section 6 Table 2.8Contingencies 0.03 $293,256 0.03 $362,256 0.03 $745,974 0.03 $977,671 OAQPS Section 6 Table 2.8Permit modifications & initial testing $50,000 $50,000 $50,000 $50,000 operating permit modifications, 40 CFR 64 compliance, initialstack testingTotal Indirect Cost, IC$3,471,323 $4,276,323 $8,753,025 $11,456,164Direct plus Indirect Cost $18,773,065 $24,371,633 $47,722,297 $62,367,584Retrofit factor 1.4 1.4 1.4 1.4 OAQPS Section 6 Ch. 2.6.1.2Total Capital Investment (TCI) = DC + IC$26,282,291 $34,120,287 $66,811,216 $87,314,6175% SO2 reduction withdry lime injection70% SO2 reduction withTrona90% SO2 Reduction w/WFGD90% SO2 Reduction w/SDAor CDSKodak BART Appendix A.xls SO2 & PM baselinePage 2 of 13Kodak ParkControl Cost Analysis9/26/20105% SO2 reduction withdry lime injection70% SO2 reduction withTrona90% SO2 Reduction w/WFGD90% SO2 Reduction w/SDAor CDSAnnual CostsOperating labor requirement 8.08.08.08.0hour/shift per OAQPS Section 6 Table 2.9hourly cost $38 $38 $38 $38 Ted Siler 9/1 emailOperating labor cost $205,090 $205,090 $205,090 $205,090Supervisory labor cost $30,764 15% $30,764 15% $30,764 15% $30,764 15% of operating labor per OAQPS Section 6 Table 2.9maintenance labor requirement 2 2 2 2 hour/shift per OAQPS Section 6 Table 2.9hourly cost $40 $40 $40 $40 Ted Siler 9/1 emailMaintenance labor cost $53,971 $53,971 $53,971 $53,971 labor costmaintenance material cost 100% $53,971 100% $53,971 100% $53,971 100% $53,971 100% of labor cost per OAQPS Section 6 Table 2.9Reagent quantity 2600 41600 13292 12333 pound/hour (vendor estimate)Reagent cost per unit $120 $180 $80 $35 $/ton (W Fleming email 9-1)Reagent annual cost $841,949 $20,206,784 $2,869,536 $1,164,845Fan Pressure Drop 2.00 2.00 12.00 6.00 inches WC pressure drop, estimate for dry sorbent, Babcock power paper for SDA, WFGDFan & Pump power 183.8 183.8 1102.8 551.4 0.000181*ACFM*pressure drop, per OAQPS Section 6 Table 3-21Electric power cost 0.07 0.07 0.07 0.07 $/kWhr (B Nee 8-30 email)Electricity cost $69,436 $69,436 $416,618 $208,309water requirement 0 0 35% 10% percent by weight reagent concentration0 0 49 222 gal/minwater unit cost $0.5 $0.5 $0.5 $0.5 per 1000 gallonswater cost $0 $0 $12,964 $58,293wastewater pretreatment $0 $0 $0 $15,543 EPA CUECost modelwastewater generated0 222wastewater unit cost$1.0 $1.0 per 1000 gallonswastewater treatment cost $0 $0 $0 $116,587solid waste generation 1.5 1.2 1.5 1 pounds of waste per pound of reagent3900 49920 19938 12333 pounds per hour$25 $25 $25 $25 $/tonsolid waste disposal cost $263,109 $3,367,797 $1,345,095 $832,032 annual landfill disposal costtotal Direct Annual costs$1,518,291 $23,987,814 $4,988,009 $2,739,405Indirect annual costsoverhead $187,819 $187,819 $187,819 $187,819 60% of op. labor, maint. labor, & maint. materialsadministration $525,646 $682,406 $1,336,224 $1,746,292 2% of total capital investmentproperty tax $262,823 $341,203 $668,112 $873,146 1% of total capital investmentinsurance $262,823 $341,203 $668,112 $873,146 1% of total capital investmentcapital recovery 0.09439 $2,480,785 0.1098 $3,746,407 0.1098 $7,335,871 0.1098 $9,587,145 factor based on 15-year life and 7% interest rate (OAQPS Ch 6 Table 2.9)total Indirect Annual Costs$3,719,897 $5,299,038 $10,196,140 $13,267,549total annualized cost$5,238,187 $29,286,852 $15,184,149 $16,006,954Emissions before control 11998 11998 11998 11998 tons/year SO2619 619 619 619 tons/year PM5% 70% 90% 90% SO2 removal (vendor estimate)80% 44% 44% 44%PM removal (vendor estimate)600 8398 10798 10798 tons SO2 removed495 272 272 272 tons PM removed$8,732 $3,487 $1,406 $1,482 dollars-per-ton average cost of control for SO2 removal$10,578 $107,530 $55,750 $58,771 dollars-per-ton average cost of control for PM removalKodak BART Appendix A.xls SO2 & PM baselinePage 3 of 13Kodak ParkControl Cost Analysis9/26/2010System operation5397 5397 hours/year507,714 507,714 ACFM airflowDirect CostsPurchased Equipment Cost $3,203,295 $10,789,724 Boiler 41 & 42 modifications (OAQPS)$2,141,106 $6,390,607 Boiler 43 modifications (OAQPS)incl. above incl. above reagent handling system$1,610,000 $1,610,000 conversion to balanced draft (vendor quote)$1,868,000 $1,868,000ID fans (W Fleming email 8-30)$50,000 $50,000 ductwork$0 $475,899 New electric utility bus (double-ended load center)(W Fleming 9-13 email)$8,872,401 $21,184,230 equipment capital cost (sum of above)Instrumentation incl. above incl. aboveSales Taxes incl. above incl. aboveFreight incl. above incl. aboveTotal Purchased Equipment Cost, PEC$8,872,401 $21,184,230Direct Installation CostsTotal Direct Installation costIncl. above Incl. aboveSite preparation $0 $0Buildings $0 $0Total Direct Cost, DC $8,872,401 $21,184,230Indirect Costs - InstallationGeneral facilities 0.05 $443,620 0.05 $1,059,212 OAQPS Section 4 Table 1.4 & 2.5engineering & home office fees 0.1 $887,240 0.1 $2,118,423 OAQPS Section 4 Table 1.4 & 2.5process contingency 0.05 $443,620 0.05 $1,059,212 OAQPS Section 4 Table 1.4 & 2.5Retrofit 0.3 $2,661,720 incl aboveTotal Indirect Installation Cost, IC$4,436,201 $4,236,846OAQPS Section 4 Table 1.4 & 2.5Project contingency 0.15 $665,430 0.15 $635,527 OAQPS Section 4 Table 1.4 & 2.5Total Plant Cost$13,974,032 $26,056,603preproduction cost 0.02 $279,481 0.02 $521,132 OAQPS Section 4 Table 1.4 & 2.5Initial Reagent $88,525 $65,010 two weeks' worth per costs belowTotal Capital Investment (TCI) = DC + IC $14,342,037 $26,642,745Selective Non-CatalyticReduction Selective Catalytic ReductionKodak BART Appendix A.xls NOx baseline Page 4 of 13Kodak ParkControl Cost Analysis9/26/2010Selective Non-CatalyticReduction Selective Catalytic ReductionAnnual Costsmaintenance cost 0.015$215,131 0.015$399,641 OAQPS Eq. 1.21, 2.46Reagent quantity 44.28 273.7 gallon/hour (SNCR scaled from OAQPS pg1-41, SCR from eq 2.32)Reagent cost per unit $0.85 $0.101 $/gallonReagent annual cost $203,136 $149,177Fan & Pump power 37.7 591.3 SNCR scaled from example, SCR per eq 4.48Electric power cost 0.07 0.07 $/kWhrElectricity cost $14,251 $223,405water requirement 3.416667 0 gal/min (SNCR scaled from example)water unit cost $0.5 $0.5 per 1000 gallonswater cost $898 $0delta coal cost 3.28 MMBtu (SNCR scaled from example)cost of coal heat $1.60 $/MMbtudelta coal cost $28,324 $0solid waste generation 24.6 0 pounds per hour (SNCR scaled from example)$25 $25 $/tonsolid waste disposal cost $1,660 $0 annual landfill disposal costCatalyst replacement cost $290 cost per cubic foot of catalyst$493,945 one-third the total catalyst per yeartotal Direct Annual costs$463,399 $1,266,169Indirect annual costsoverhead $0 $0 negligible per OAQPSadministration $0 $0 negligible per OAQPSproperty tax $0 $0 negligible per OAQPSinsurance $0 $0 negligible per OAQPScapital recovery 0.0944 $1,353,745 0.09439 $2,514,809 capital recovery factor based on 20-year life and 7% interest ratetotal Indirect Annual Costs$1,353,745 $2,514,809total annualized cost$1,817,144 $3,780,977Emissions before control 2449 2449 tons/year NOx35% 70% NOx removal857.0917 1714.18 tons NOx removed$2,120 $2,206 dollars-per-ton cost effectiveness for NOx removalKodak BART Appendix A.xls NOx baseline Page 5 of 13Kodak ParkControl Cost Analysis9/26/2010System operation4312 4312 4312 4312 hours/year507,714 507,714 507,714 507,714 ACFM airflowDirect CostsPurchased Equipment Cost $2,100,000 $2,100,000 $4,800,000 $8,200,000 Boiler 41 & 42 modifications (vendor quote)$1,250,000 $1,250,000 $3,900,000 $6,500,000 Boiler 43 modifications (vendor quote)$1,100,000 $3,100,000 $1,300,000 $1,800,000 reagent handling system (vendor quote)$1,610,000 $1,610,000 $1,610,000 $1,610,000 conversion to balanced draft (vendor quote)$1,868,000 $1,868,000 $1,868,000 $1,868,000 ID fans (W Fleming email 8-30)$50,000 $50,000 $7,146,342 $7,146,342 ductwork (truss bridge for SDA & WFGD; W Fleming 9-13 email)$0 $0 $475,899 $475,899 New electric utility bus (double-ended load center)(W Fleming 9-13 email)$482,182 $482,182 $482,182 $482,182 Stack liner (Pennguard Block, W Fleming 9-13 email)$40,000 $40,000 $40,000 $40,000 SO2 emission monitor (consultant estimate)$0 $0 $0 $215,872 wastewater pretreatment & sludge thickening (EPA CUECost model)$8,500,182 $10,500,182 $21,622,423 $28,338,295 equipment capital cost (sum of above)Instrumentation 0.1 $850,018 0.1 $1,050,018 0.1 $2,162,242 0.1 $2,833,830 OAQPS Section 6 Table 2.8Sales Taxes 0 $0 0 $0 0 $0 0 $0 tax exempt per http://www.tax.state.ny.us/pdf/current_forms/st/st121_fill_in.pdfFreight 0.05 $425,009 0.05 $525,009 0.05 $1,081,121 0.05 $1,416,915 OAQPS Section 6 Table 2.8Total Purchased Equipment Cost, PEC$9,775,209 $12,075,209 $24,865,787 $32,589,040Direct Installation CostsFoundations and supports 0.06 $586,513 0.06 $724,513 0.06 $1,491,947 0.06 $1,955,342 OAQPS Section 6 Table 2.8Handling and erection 0.4 $3,910,084 0.4 $4,830,084 0.4 $9,946,315 0.4 $13,035,616 OAQPS Section 6 Table 2.8Electrical 0.01 $97,752 0.01 $120,752 0.01 $248,658 0.01 $325,890 OAQPS Section 6 Table 2.8Piping 0.05 $488,760 0.05 $603,760 0.05 $1,243,289 0.05 $1,629,452 OAQPS Section 6 Table 2.8Insulation for ductwork 0.03 $293,256 0.03 $362,256 0.03 $745,974 0.03 $977,671 OAQPS Section 6 Table 2.8Painting 0.01 $97,752 0.01 $120,752 0.01 $248,658 0.01 $325,890 OAQPS Section 6 Table 2.8Total Direct Installation cost$5,474,117 $6,762,117 $13,924,841 $18,249,862Site preparation $0 $0 $0 $0Buildings $0 $0 $0 $0Initial Reagent $52,416 $1,257,984 $178,644 $72,518 two weeks' worth per costs belowTotal Direct Cost, DC $15,301,742 $20,095,310 $38,969,272 $50,911,420Indirect Costs - InstallationEngineering 0.1 $977,521 0.1 $1,207,521 0.1 $2,486,579 0.1 $3,258,904 OAQPS Section 6 Table 2.8Construction and field expenses 0.1 $977,521 0.1 $1,207,521 0.1 $2,486,579 0.1 $3,258,904 OAQPS Section 6 Table 2.8Contractor fees 0.1 $977,521 0.1 $1,207,521 0.1 $2,486,579 0.1 $3,258,904 OAQPS Section 6 Table 2.8Start-up 0.01 $97,752 0.01 $120,752 0.01 $248,658 0.01 $325,890 OAQPS Section 6 Table 2.8Performance test 0.01 $97,752 0.01 $120,752 0.01 $248,658 0.01 $325,890 OAQPS Section 6 Table 2.8Contingencies 0.03 $293,256 0.03 $362,256 0.03 $745,974 0.03 $977,671 OAQPS Section 6 Table 2.8Permit modifications & initial testing $50,000 $50,000 $50,000 $50,000 operating permit modifications, 40 CFR 64 compliance, initialstack testingTotal Indirect Cost, IC$3,471,323 $4,276,323 $8,753,025 $11,456,164Direct plus Indirect Cost $18,773,065 $24,371,633 $47,722,297 $62,367,584Retrofit factor 1.4 1.4 1.4 1.4 OAQPS Section 6 Ch. 2.6.1.25% SO2 reduction withdry lime injection70% SO2 reduction withTrona90% SO2 Reduction w/WFGD90% SO2 Reduction w/SDAor CDSKodak BART Appendix A.xls SO2 & PM Incremental Page 6 of 13Kodak ParkControl Cost Analysis9/26/20105% SO2 reduction withdry lime injection70% SO2 reduction withTrona90% SO2 Reduction w/WFGD90% SO2 Reduction w/SDAor CDSTotal Capital Investment (TCI) = DC + IC$26,282,291 $34,120,287 $66,811,216 $87,314,617Annual CostsOperating labor requirement 8.08.08.08.0hour/shift per OAQPS Section 6 Table 2.9hourly cost $38 $38 $38 $38 Ted Siler 9/1 emailOperating labor cost $163,843 $163,843 $163,843 $163,843Supervisory labor cost $24,577 15% $24,577 15% $24,577 15% $24,577 15% of operating labor per OAQPS Section 6 Table 2.9maintenance labor requirement 2 2 2 2 hour/shift per OAQPS Section 6 Table 2.9hourly cost $40 $40 $40 $40 Ted Siler 9/1 emailMaintenance labor cost $43,117 $43,117 $43,117 $43,117 labor costmaintenance material cost 100% $43,117 100% $43,117 100% $43,117 100% $43,117 100% of labor cost per OAQPS Section 6 Table 2.9Reagent quantity 2600 41600 13292 12333 pound/hour (vendor estimate)Reagent cost per unit $120 $180 $80 $35 $/ton (W Fleming email 9-1)Reagent annual cost $672,620 $16,142,880 $2,292,427 $930,576Fan Pressure Drop 2.00 2.00 12.00 6.00 inches WC pressure drop, estimate for dry sorbent, Babcock power paper for SDA, WFGDFan & Pump power 183.8 183.8 1102.8 551.4 0.000181*ACFM*pressure drop, per OAQPS Section 6 Table 3-21Electric power cost 0.07 0.07 0.07 0.07 $/kWhr (B Nee 8-30 email)Electricity cost $55,472 $55,472 $332,830 $166,415water requirement 0 0 35% 10% percent by weight reagent concentration0 0 49 222 gal/minwater unit cost $0.5 $0.5 $0.5 $0.5 per 1000 gallonswater cost $0 $0 $12,964 $58,293wastewater pretreatment $0 $0 $0 $15,543 EPA CUECost modelwastewater generated0 222wastewater unit cost$1.0 $1.0 per 1000 gallonswastewater treatment cost $0 $0 $0 $116,587solid waste generation 1.5 1.2 1.5 1 pounds of waste per pound of reagent3900 49920 19938 12333 pounds per hour$25 $25 $25 $25 $/tonsolid waste disposal cost $210,194 $2,690,480 $1,074,575 $664,697 annual landfill disposal costtotal Direct Annual costs$1,212,939 $19,163,485 $3,987,449 $2,226,765Indirect annual costsoverhead $150,046 $150,046 $150,046 $150,046 60% of op. labor, maint. labor, & maint. materialsadministration $525,646 $682,406 $1,336,224 $1,746,292 2% of total capital investmentproperty tax $262,823 $341,203 $668,112 $873,146 1% of total capital investmentinsurance $262,823 $341,203 $668,112 $873,146 1% of total capital investmentcapital recovery 0.09439 $2,480,785 0.1098 $3,746,407 0.1098 $7,335,871 0.1098 $9,587,145 factor based on 15-year life and 7% interest rate (OAQPS Ch 6 Table 2.9)total Indirect Annual Costs$3,682,123 $5,261,265 $10,158,366 $13,229,776total annualized cost$4,895,062 $24,424,750 $14,145,815 $15,456,540Emissions before control 9843 9843 9843 9843 tons/year SO2544 544 544 544 tons/year PM5% 70% 90% 90% SO2 removal (vendor estimate)80% 44% 44% 44%PM removal (vendor estimate)492 6890 8858 8858 tons SO2 removed435 239 239 239 tons PM removed$9,947 $3,545 $1,597 $1,745 dollars-per-ton average cost of control for SO2 removal$11,255 $102,104 $59,135 $64,614 dollars-per-ton average cost of control for PM removalKodak BART Appendix A.xls SO2 & PM Incremental Page 7 of 13Kodak ParkControl Cost Analysis9/26/2010System operation4312 4312 hours/year507,714 507,714 ACFM airflowDirect CostsPurchased Equipment Cost $3,203,295 $10,789,724 Boiler 41 & 42 modifications (OAQPS)$2,141,106 $6,390,607 Boiler 43 modifications (OAQPS)incl. above incl. above reagent handling system$1,610,000 $1,610,000 conversion to balanced draft (vendor quote)$1,868,000 $1,868,000ID fans (W Fleming email 8-30)$50,000 $50,000 ductwork$0 $475,899 New electric utility bus (double-ended load center)(W Fleming 9-13 email)$8,872,401 $21,184,230 equipment capital cost (sum of above)Instrumentation incl. above incl. aboveSales Taxes incl. above incl. aboveFreight incl. above incl. aboveTotal Purchased Equipment Cost, PEC$8,872,401 $21,184,230Direct Installation CostsTotal Direct Installation costIncl. above Incl. aboveSite preparation $0 $0 (PLACEHOLDER ESTIMATE)Buildings $0 $0 (PLACEHOLDER ESTIMATE)Total Direct Cost, DC $8,872,401 $21,184,230Indirect Costs - InstallationGeneral facilities 0.05 $443,620 0.05 $1,059,212 OAQPS Section 4 Table 1.4 & 2.5engineering & home office fees 0.1 $887,240 0.1 $2,118,423 OAQPS Section 4 Table 1.4 & 2.5process contingency 0.05 $443,620 0.05 $1,059,212 OAQPS Section 4 Table 1.4 & 2.5Retrofit 0.3 $2,661,720 incl aboveTotal Indirect Installation Cost, IC$4,436,201 $4,236,846OAQPS Section 4 Table 1.4 & 2.5Project contingency 0.15 $665,430 0.15 $635,527 OAQPS Section 4 Table 1.4 & 2.5Total Plant Cost$13,974,032 $26,056,603preproduction cost 0.02 $279,481 0.02 $521,132 OAQPS Section 4 Table 1.4 & 2.5Initial Reagent $88,525 $65,010 two weeks' worth per costs belowTotal Capital Investment (TCI) = DC + IC $14,342,037 $26,642,745Selective Non-CatalyticReductionSelective CatalyticReductionKodak BART Appendix A.xls NOx Incremental Page 8 of 13Kodak ParkControl Cost Analysis9/26/2010Selective Non-CatalyticReductionSelective CatalyticReductionAnnual Costsmaintenance cost 0.015$215,131 0.015$399,641 OAQPS Eq. 1.21, 2.46Reagent quantity 44.28 273.7 gallon/hour (SNCR scaled from OAQPS pg1-41, SCR from eq 2.32)Reagent cost per unit $0.85 $0.101 $/gallonReagent annual cost $162,283 $119,175Fan & Pump power 37.7 591.3 SNCR scaled from example, SCR per eq 4.48Electric power cost 0.07 0.07 $/kWhrElectricity cost $11,385 $178,475water requirement 3.41667 0 gal/min (SNCR scaled from example)water unit cost $0.5 $0.5 per 1000 gallonswater cost $898 $0delta coal cost 3.28 MMBtu (SNCR scaled from example)cost of coal heat $1.60 $/MMbtudelta coal cost $22,628 $0solid waste generation 24.6 0 pounds per hour (SNCR scaled from example)$25 $25 $/ton (PLACEHOLDER ESTIMATE)solid waste disposal cost $1,326 $0 annual landfill disposal costCatalyst replacement cost $290 cost per cubic foot of catalyst$493,945 one-third the total catalyst per yeartotal Direct Annual costs$413,649 $1,191,237Indirect annual costsoverhead $0 $0 negligible per OAQPSadministration $0 $0 negligible per OAQPSproperty tax $0 $0 negligible per OAQPSinsurance $0 $0 negligible per OAQPScapital recovery 0.09439 $1,353,745 0.09439 $2,514,809 capital recovery factor based on 20-year life and 7% interest ratetotal Indirect Annual Costs$1,353,745 $2,514,809total annualized cost$1,767,394 $3,706,045Emissions before control 1969 1969 tons/year NOx35% 70% NOx removal689.267 1378.53 tons NOx removed$2,564 $2,688 dollars-per-ton cost effectiveness for NOx removalKodak BART Appendix A.xls NOx Incremental Page 9 of 13SNCR capital cost (OAQPS Section 4 Chapter 1.2)

Boiler 41, 42 43 Qb = 500 640 n(Nox)= 35% 35%
DC $1,117,595 $1,494,018 Retrofit factor 1.3 1.3 OAQPS Control Cost Manual Section 4 Chapter 1.4 $1,452,874.02 $1,942,223.2 389.5 1998 Chemical Engineering Plant Cost Index 558.2 May 2010 Chemical Engineering Plant Cost Index (latest avail).
adjusted DC: $1,601,648 $2,141,106

Kodak BART Appendix A.xls NOx sizing Page 10 of 13SCR Capital Cost (OAQPS Section 4 Chapter 2) Boilers 41&42 Boiler 43 N 70% 70%
slip: 5 5 ppm S 3.1 3.1 percent sulfur in coal T 700.0 700.0 F (assumed temp. where hot-SCR would be installed) N(inlet) 0.62 0.62 lb/MMBtu inlet NOx catalyst volume

Qb= 500 640 MMBtu/hr n(adj)= .2869+(1.058*N) 1.0275 1.0275 slip(adj)= 1.2835-(0.0567*slip) 1 1 S(adj)= 0.9636+(0.0455XS) 1.10465 1.10465 T(adj)= 15.16-(.03937*T)+(2.74e-5*T^2) 1.027 1.027 N(SCR)= 0.8524+(0.3208*N(inlet)) 1.051296 1.051296 Vol(cat)= 1558 1994
Reagent use 120.5 154.2 lb/hr as NH3 634 812 lb/hr as 19% aqueous NH3 83.4 106.8 gal/hr as 19% aqueous NH3 28034 35884 gallon storage needed for 14-day supply

f(new)=0, assume h(SCR)=0, f(bypass)=0 f(NH3) 51.73 51.73 DC= $3,764,419 $4,459,229
389.5 1998 Chemical Engineering Plant Cost Index 558.2 May 2010 Chemical Engineering Plant Cost Index (latest avail).
adjusted DC: $5,394,862 $6,390,607

Kodak BART Appendix A.xls NOx sizing Page 11 of 13KODAK PARKBART Control Cost Baselineaj/Epsilon 9/26/10Total Source41 42 432007 NOx 509.6 893.5 958.3 2,361.4 EPA CAMD2008 NOx 522.9 1030.1 1391.5 2,944.5 EPA CAMD2009 NOx 406 806.3 828.3 2,040.6 EPA CAMDNOx Baseline, tons/year: 2,448.82007 SO2 2108 4141 4089 10,338.0 Kodak Park Air Emission Statement reports2008 SO2 2379 5454 6963 14,796.0 Kodak Park Air Emission Statement reports2009 SO2 1978 4315 4566 10,859.0 Kodak Park Air Emission Statement reportsSO2 Baseline, tons/year: 11,997.72007 PM10 78 221 255 554.0 Kodak Park Air Emission Statement reports2008 PM10 80 261 355 696.0 Kodak Park Air Emission Statement reports2009 PM10 68 253 286 607.0 Kodak Park Air Emission Statement reportsPM10 Baseline, tons/year: 619.0PM10 includes filterable and condensable emissionsAverage2007 hours 3425 6630 5705 52532008 hours 3414 7477 7583 61582009 hours 2930 6129 5281 4780Hours/year, average: 5,397BoilerKODAK PARKBART Control Cost Restricted Optionaj/Epsilon 9/26/10Total Source41 42 432007 NOx 893.5 958.3 1,851.8 EPA CAMD2008 NOx 1030.1 1391.5 2,421.6 EPA CAMD2009 NOx 806.3 828.3 1,634.6 EPA CAMDNOx Restricted Option, tons/year: 1,969.32007 SO2 4141 4089 8,230.0 Kodak Park Air Emission Statement reports2008 SO2 5454 6963 12,417.0 Kodak Park Air Emission Statement reports2009 SO2 4315 4566 8,881.0 Kodak Park Air Emission Statement reportsSO2 Restricted Option, tons/year: 9,842.72007 PM10 221 255 476.0 Kodak Park Air Emission Statement reports2008 PM10 261 355 616.0 Kodak Park Air Emission Statement reports2009 PM10 253 286 539.0 Kodak Park Air Emission Statement reportsPM10 Restricted Option, tons/year: 543.7Assume PM10 is filterable-onlyAverage2007 hours 0 6630 5705 41122008 hours 0 7477 7583 50202009 hours 0 6129 5281 3803Hours/year, Retricted Option, average: 4,312Boiler

## Appendix B Air Quality Dispersion Modeli ng Supporting DocumentationJulian Day hr 0

All 1 1.793 330 76.35 22.66 0.36 0.14 0.13 0.36 8 0.903 217 95.07 4.15 0.29 0.11 0.10 0.29 Boilers 41& 42 1 1.166 330 78.01 21.15 0.26 0.13 0.12 0.33 8 0.595 217 95.56 3.79 0.20 0.10 0.08 0.26 Boiler 43 1 0.688 330 73.48 25.27 0.54 0.16 0.15 0.4 8 0.341 290 79.28 19.84 0.40 0.12 0.07 0.3 Package Boilers 1 0.009 330 63.7 35.57 0 0 0.58 0.15 8 0.004 217 93.36 5.99 0 0 0.51 0.14

All 1 1.288 18 77.04 22.32 0.25 0.1 0.05 0.24 8 0.495 90 87.94 11.07 0.4 0.15 0.07 0.37 Boilers 41& 42 1 0.845 18 78.79 20.67 0.18 0.09 0.04 0.22 8 0.321 90 89.01 10.18 0.28 0.13 0.07 0.34 Boiler 43 1 0.472 18 73.93 25.24 0.39 0.11 0.06 0.28 8 0.194 21 72.84 26.02 0.55 0.16 0.06 0.38 Package Boilers 1 0.006 18 64.89 34.79 0 0 0.22 0.1 8 0.002 217 98.51 1.18 0 0 0.21 0.08

All 1 0.961 330 75.74 23.03 0.50 0.18 0.11 0.45 8 0.417 254 94.18 5.21 0.24 0.09 0.05 0.23 Boilers 41& 42 1 0.607 330 77.43 21.53 0.36 0.17 0.10 0.42 8 0.276 254 94.69 4.81 0.17 0.08 0.04 0.21 Boiler 43 1 0.369 330 72.96 25.46 0.74 0.21 0.12 0.52 8 0.147 140 88.97 9.77 0.6 0.17 0.08 0.41 Package Boilers 1 0.004 330 63.33 35.99 0 0 0.49 0.18 8 0.002 213 96.87 2.66 0 0 0.33 0.13

All 1 1.326 223 95.65 3.80 0.22 0.08 0.05 0.21 8 0.765 48 78.26 20.71 0.40 0.15 0.09 0.39 Boilers 41& 42 1 0.874 223 96.11 3.44 0.15 0.07 0.04 0.18 8 0.489 48 79.95 19.19 0.29 0.14 0.08 0.35 Boiler 43 1 0.483 223 94.79 4.46 0.34 0.10 0.06 0.25 8 0.285 48 75.38 23.28 0.61 0.18 0.10 0.45 Package Boilers 1 0.005 340 63.25 36.35 0 0 0.26 0.12 8 0.003 48 66.66 32.80 0 0 0.40 0.15 

## Predicted using the Hybrid Meteorological Data Set Eastman Business Park Base Case Visibility Impacts (delta deciview)

Presidential Ran g e – Dr y River %

_ PMF L y e Brook Wilderness Area

Acadia National Park

Bri g antine National Wildlife Refu g e Hybrid 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) %

_ SO4 %

_ NO3 %

_ OC %

_ EC %

_ PMCJulian Day hr 0

All 1 1.287 223 95.66 3.79 0.22 0.08 0.05 0.21 8 0.720 48 78.29 20.69 0.39 0.15 0.09 0.38 Boilers 41& 42 1 0.847 223 96.11 3.44 0.15 0.07 0.04 0.19 8 0.461 48 79.98 19.17 0.28 0.14 0.08 0.35 Boiler 43 1 0.470 223 94.81 4.45 0.34 0.10 0.06 0.25 8 0.265 309 78.02 21.24 0.34 0.10 0.06 0.25 Package Boilers 1 0.005 340 63.55 36.07 0 0 0.25 0.12 8 0.003 48 66.70 32.75 0 0 0.40 0.15

All 1 1.205 233 93.49 6.04 0.2 0.07 0.03 0.18 8 0.180 240 94.32 5.18 0.2 0.07 0.04 0.19 Boilers 41& 42 1 0.763 233 94.00 5.62 0.13 0.06 0.03 0.16 8 0.118 240 94.88 4.71 0.14 0.07 0.03 0.17 Boiler 43 1 0.469 233 92.62 6.74 0.31 0.09 0.04 0.22 8 0.062 240 93.30 6.02 0.32 0.09 0.04 0.23 Package Boilers 1 0.004 233 90.17 9.61 0 0 0.14 0.07 8 0.001 261 94.84 4.87 0 0 0.21 0.06

All 1 1.022 233 93.83 5.70 0.19 0.07 0.03 0.18 8 0.180 240 94.29 5.21 0.2 0.07 0.04 0.19 Boilers 41& 42 1 0.646 233 94.31 5.32 0.13 0.06 0.03 0.15 8 0.117 240 94.85 4.74 0.14 0.07 0.03 0.17 Boiler 43 1 0.396 233 93.06 6.31 0.30 0.09 0.04 0.21 8 0.062 240 93.26 6.06 0.32 0.09 0.04 0.23 Package Boilers 1 0.004 233 90.43 9.35 0 0 0.15 0.07 8 0.001 220 91.32 8.06 0 0 0.48 0.16 Otter Creek 

## Predicted using the Hybrid Meteorological Data Set (Continued) Eastman Business Park Base Case Visibility Impacts (delta deciview)

% PMC % PMF Great Gulf

Doll y Sods Hybrid 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) % SO4 % NO3 % OC % ECJulian Day hr 0

All 1 1.380 330 77.2 21.72 0.40 0.15 0.14 0.39 8 0.697 217 95.41 3.73 0.32 0.12 0.10 0.31 Boilers 41& 42 1 0.728 330 80.78 18.28 0.27 0.15 0.13 0.38 8 0.382 217 96.48 2.82 0.21 0.11 0.09 0.29

All 1 0.976 18 77.81 21.48 0.28 0.11 0.05 0.27 8 0.372 90 88.52 10.40 0.44 0.16 0.08 0.4 Boilers 41& 42 1 0.520 18 81.47 17.94 0.19 0.10 0.05 0.25 8 0.196 90 90.81 8.30 0.29 0.15 0.07 0.37

All 1 0.724 330 76.56 22.08 0.55 0.20 0.12 0.5 8 0.321 254 94.29 5.04 0.27 0.10 0.05 0.25 Boilers 41& 42 1 0.363 330 80.31 18.53 0.37 0.19 0.11 0.48 8 0.174 213 98.21 1.09 0.23 0.12 0.06 0.29

All 1 0.976 223 95.86 3.53 0.24 0.09 0.05 0.22 8 0.558 48 78.84 20.02 0.45 0.17 0.10 0.42 Boilers 41& 42 1 0.509 223 96.87 2.64 0.15 0.08 0.05 0.21 8 0.277 48 82.60 16.46 0.29 0.16 0.09 0.4 (Boiler 43 and package boiler impacts unchanged from baseline case) 

## Predicted using the Hybrid Meteorological Data Set Eastman Business Park Restricted Case Visibility Impacts (delta deciview)

Presidential Ran g e – Dr y River %

_ PMF L y e Brook Wilderness Area

Acadia National Park

Bri g antine National Wildlife Refu g e Hybrid 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) %

_ SO4 %

_ NO3 %

_ OC %

_ EC %

_ PMCJulian Day hr 0

All 1 0.943 223 95.86 3.52 0.24 0.09 0.05 0.22 8 0.525 48 78.9 19.98 0.44 0.16 0.1 0.42 Boilers 41& 42 1 0.488 223 96.88 2.63 0.15 0.08 0.05 0.21 8 0.262 48 82.56 16.51 0.29 0.16 0.09 0.4

All 1 0.883 233 93.75 5.73 0.22 0.08 0.03 0.19 8 0.132 240 94.48 4.97 0.23 0.08 0.04 0.21 Boilers 41& 42 1 0.427 233 95.01 4.61 0.13 0.07 0.03 0.17 8 0.070 240 95.56 3.99 0.14 0.08 0.04 0.19

All 1 0.749 233 94.08 5.41 0.21 0.08 0.03 0.19 8 0.132 240 94.44 5 0.22 0.08 0.04 0.21 Boilers 41& 42 1 0.364 233 95.18 4.44 0.12 0.06 0.03 0.16 8 0.070 240 95.54 4.02 0.14 0.08 0.04 0.19 Otter Creek 

## Predicted using the Hybrid Meteorological Data Set (Continued) Eastman Business Park Restricted Case Visibility Impacts (delta deciview)

% PMC % PMF Great Gulf

Doll y Sods Hybrid 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) % SO4 % NO3 % OC % ECJulian Day hr 0

All 1 1.478 330 90.80 8.61 0.45 0.03 0.03 0.08 8 0.812 290 93.27 6.33 0.30 0.02 0.01 0.06 Boilers 41& 42 1 0.958 330 91.74 7.81 0.32 0.03 0.03 0.07 8 0.548 290 93.97 5.73 0.21 0.02 0.01 0.05 Boiler 43 1 0.558 330 89.47 9.68 0.69 0.04 0.04 0.09 8 0.292 29 90.51 8.46 0.84 0.04 0.04 0.11

All 1 1.043 18 91.19 8.41 0.31 0.02 0.01 0.05 8 0.439 90 95.70 3.72 0.45 0.03 0.02 0.08 Boilers 41& 42 1 0.695 18 92.13 7.57 0.22 0.02 0.01 0.05 8 0.284 90 96.23 3.34 0.32 0.03 0.01 0.07 Boiler 43 1 0.364 18 89.76 9.64 0.50 0.02 0.01 0.07 8 0.161 5 86.15 12.72 0.93 0.05 0.03 0.12

All 1 0.776 330 90.49 8.72 0.62 0.04 0.03 0.1 8 0.381 114 93.57 5.56 0.68 0.04 0.03 0.11 Boilers 41& 42 1 0.497 330 91.47 7.93 0.44 0.04 0.02 0.1 8 0.253 213 99.27 0.41 0.24 0.02 0.01 0.05 Boiler 43 1 0.288 330 89.13 9.73 0.94 0.05 0.03 0.12 8 0.129 140 95.93 3.25 0.68 0.03 0.02 0.09

All 1 1.223 223 98.52 1.18 0.23 0.02 0.01 0.04 8 0.628 48 91.68 7.69 0.49 0.03 0.02 0.09 Boilers 41& 42 1 0.801 223 98.74 1.04 0.16 0.01 0.01 0.04 8 0.400 30 93.49 6.13 0.28 0.02 0.01 0.06 Boiler 43 1 0.448 223 98.15 1.40 0.37 0.02 0.01 0.05 8 0.230 48 90.37 8.70 0.76 0.04 0.02 0.1 

## Predicted using the Hybrid Meteorological Data Set Eastman Business Park SCR-Lime Case Visibility Impacts (delta deciview)

Presidential Ran g e – Dr y River %

_ PMF L y e Brook Wilderness Area

Acadia National Park

Bri g antine National Wildlife Refu g e Hybrid 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) %

_ SO4 %

_ NO3 %

_ OC %

_ EC %

_ PMCJulian Day hr 0

All 1 1.186 223 98.52 1.18 0.24 0.02 0.01 0.04 8 0.588 48 91.64 7.73 0.48 0.03 0.02 0.09 Boilers 41& 42 1 0.774 223 98.74 1.04 0.16 0.01 0.01 0.04 8 0.379 48 92.55 6.98 0.34 0.03 0.02 0.08 Boiler 43 1 0.436 223 98.16 1.39 0.37 0.02 0.01 0.05 8 0.213 48 90.32 8.77 0.75 0.04 0.02 0.1

All 1 1.093 233 97.78 1.95 0.21 0.01 0.01 0.04 8 0.165 240 98.06 1.66 0.22 0.01 0.01 0.04 Boilers 41& 42 1 0.693 233 98.01 1.80 0.14 0.01 0.01 0.03 8 0.109 240 98.31 1.48 0.15 0.01 0.01 0.03 Boiler 43 1 0.422 233 97.44 2.15 0.34 0.02 0.01 0.04 8 0.057 240 97.67 1.91 0.35 0.02 0.01 0.05

All 1 0.928 233 97.89 1.84 0.21 0.01 0.01 0.04 8 0.165 240 98.05 1.67 0.22 0.01 0.01 0.04 Boilers 41& 42 1 0.588 233 98.11 1.7 0.14 0.01 0.01 0.03 8 0.108 240 98.30 1.49 0.15 0.01 0.01 0.03 Boiler 43 1 0.355 233 97.59 2.01 0.33 0.02 0.01 0.04 8 0.057 240 97.66 1.92 0.35 0.02 0.01 0.05 Otter Creek 

## Predicted using the Hybrid Meteorological Data Set (Continued) Eastman Business Park SCR-Lime Case Visibility Impacts (delta deciview)

% PMC % PMF Great Gulf

Doll y Sods Hybrid 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) % SO4 % NO3 % OC % ECJulian Day hr 0

All 1 0.392 330 62.81 34.78 1.83 0.13 0.13 0.33 8 0.165 11 61.84 34.89 2.51 0.17 0.14 0.45 Boilers 41& 42 1 0.224 330 62.40 35.53 1.47 0.13 0.12 0.34 8 0.089 339 68.58 29.14 1.66 0.15 0.10 0.38 Boiler 43 1 0.163 330 63.30 33.71 2.42 0.13 0.12 0.33 8 0.073 290 67.10 30.50 1.97 0.10 0.06 0.27

All 1 0.258 18 61.45 36.80 1.37 0.09 0.05 0.24 8 0.083 217 96.69 1.59 1.34 0.09 0.06 0.23 Boilers 41& 42 1 0.149 18 61.49 37.04 1.08 0.09 0.05 0.24 8 0.049 217 97.04 1.56 1.03 0.09 0.05 0.23 Boiler 43 1 0.105 18 61.16 36.59 1.86 0.09 0.05 0.24 8 0.032 217 96.00 1.66 1.93 0.10 0.06 0.25

All 1 0.209 330 63.93 33.08 2.35 0.15 0.10 0.4 8 0.083 261 83.88 14.09 1.59 0.10 0.06 0.27 Boilers 41& 42 1 0.116 330 63.16 34.27 1.90 0.16 0.09 0.41 8 0.047 337 63.51 33.59 2.15 0.18 0.09 0.47 Boiler 43 1 0.089 330 64.93 31.40 3.04 0.15 0.09 0.39 8 0.034 238 91.52 6.03 2.04 0.10 0.05 0.25

All 1 0.246 340 61.37 36.50 1.66 0.11 0.06 0.29 8 0.141 195 86.05 11.69 1.75 0.12 0.09 0.31 Boilers 41& 42 1 0.139 340 61.27 36.94 1.32 0.12 0.06 0.3 8 0.078 30 66.82 31.27 1.41 0.12 0.06 0.32 Boiler 43 1 0.103 340 61.40 35.92 2.21 0.11 0.06 0.29 8 0.058 5 59.74 36.19 3.31 0.17 0.14 0.45 

## Predicted using the Hybrid Meteorological Data Set Eastman Business Park SCR-SDA Case Visibility Impacts (delta deciview)

Presidential Ran g e – Dr y River %

_ PMF L y e Brook Wilderness Area

Acadia National Park

Bri g antine National Wildlife Refu g e Hybrid 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) %

_ SO4 %

_ NO3 %

_ OC %

_ EC %

_ PMCJulian Day hr 0

All 1 0.218 340 61.28 36.67 1.60 0.11 0.06 0.28 8 0.136 106 80.52 16.81 2.07 0.14 0.10 0.37 Boilers 41& 42 1 0.124 340 61.24 37.05 1.26 0.11 0.05 0.29 8 0.077 30 66.80 31.29 1.41 0.12 0.06 0.32 Boiler 43 1 0.091 340 61.21 36.19 2.15 0.11 0.06 0.29 8 0.056 18 61.31 35.69 2.47 0.13 0.08 0.33

All 1 0.159 233 85.92 12.47 1.27 0.08 0.04 0.22 8 0.026 240 87.40 10.81 1.41 0.09 0.05 0.24 Boilers 41& 42 1 0.092 233 86.53 12.17 0.96 0.08 0.04 0.21 8 0.015 240 87.78 10.77 1.08 0.09 0.05 0.24 Boiler 43 1 0.063 233 84.73 13.09 1.81 0.09 0.04 0.23 8 0.010 240 86.59 11.01 1.99 0.10 0.05 0.26

All 1 0.134 233 86.29 12.11 1.26 0.08 0.04 0.21 8 0.026 240 87.33 10.88 1.41 0.09 0.05 0.24 Boilers 41& 42 1 0.078 233 86.86 11.86 0.96 0.08 0.04 0.21 8 0.015 240 87.71 10.84 1.08 0.09 0.05 0.24 Boiler 43 1 0.053 233 85.18 12.66 1.80 0.09 0.04 0.23 8 0.010 240 86.52 11.09 1.99 0.10 0.05 0.26 Otter Creek 

## Predicted using the Hybrid Meteorological Data Set (Continued) Eastman Business Park SCR-SDA Case Visibility Impacts (delta deciview)

% PMC % PMF Great Gulf

Doll y Sods Hybrid 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) % SO4 % NO3 % OC % EC

## Eastman Business Park Number of Days with Visibility Impa cts (delta deciview ) Above Thresholds Predicted using the Hybrid Meteorological Data Set

Operating Scenario # of Days with Change in Vis

=>0.1 ddv # of Days with Change in Vis

=>0.5 ddv # of Days with Change in Vis

=>1.0 ddv Maximum Change in Vis (ddv) Lye Brook Wilderness Area Base Case All (B 41,42,43 & PB1-4) 113 24 6 1.793 Boilers 41 & 42 85 11 1 1.166 Boiler 43 44 5 0 0.688 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 94 15 4 1.380 Boilers 41 & 42 49 3 0 0.728 SCR & Lime DSI All (B 41,42,43 & PB1-4) 104 21 5 1.478 Boilers 41 & 42 72 9 0 0.958 Boiler 43 34 1 0 0.558 SCR & SDA All (B 41,42,43 & PB1-4) 24 0 0 0.392 Boilers 41 & 42 7 0 0 0.224 Boiler 43 3 0 0 0.163 Acadia National Park Base Case All (B 41,42,43 & PB1-4) 61 7 1 1.288 Boilers 41 & 42 36 2 0 0.845 Boiler 43 15 0 0 0.472 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 47 5 0 0.976 Boilers 41 & 42 18 1 0 0.520 SCR & Lime DSI All (B 41,42,43 & PB1-4) 50 6 1 1.043 Boilers 41 & 42 30 2 0 0.695 Boiler 43 14 0 0 0.364 SCR & SDA All (B 41,42,43 & PB1-4) 5 0 0 0.258 Boilers 41 & 42 1 0 0 0.149 Boiler 43 1 0 0 0.105

### 2



## Eastman Business Park (Continued) Number of Days with Visibility Impa cts (delta deciview ) Above Thresholds Predicted using the Hybrid Meteorological Data Set

Operating Scenario # of Days with Change in Vis

=>0.1 ddv # of Days with Change in Vis

=>0.5 ddv # of Days with Change in Vis

=>1.0 ddv Maximum Change in Vis (ddv) Brigantine National Wildlife Refuge Base Case All (B 41,42,43 & PB1-4) 66 6 0 0.961 Boilers 41 & 42 42 3 0 0.607 Boiler 43 22 0 0 0.369 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 53 3 0 0.724 Boilers 41 & 42 22 0 0 0.363 SCR & Lime DSI All (B 41,42,43 & PB1-4) 56 5 0 0.776 Boilers 41 & 42 38 0 0 0.497 Boiler 43 15 0 0 0.288 SCR & SDA All (B 41,42,43 & PB1-4) 4 0 0 0.209 Boilers 41 & 42 1 0 0 0.116 Boiler 43 0 0 0 0.089 Presidential Range – Dry River Base Case All (B 41,42,43 & PB1-4) 79 14 4 1.326 Boilers 41 & 42 62 7 0 0.874 Boiler 43 36 0 0 0.483 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 70 8 0 0.976 Boilers 41 & 42 37 1 0 0.509 SCR & Lime DSI All (B 41,42,43 & PB1-4) 75 12 2 1.223 Boilers 41 & 42 55 5 0 0.801 Boiler 43 30 0 0 0.448 SCR & SDA All (B 41,42,43 & PB1-4) 13 0 0 0.246 Boilers 41 & 42 2 0 0 0.139 Boiler 43 1 0 0 0.103

### 3



## Eastman Business Park (Continued) Number of Days with Visibility Impa cts (delta deciview ) Above Thresholds Predicted using the Hybrid Meteorological Data Set

Operating Scenario # of Days with Change in Vis

=>0.1 ddv # of Days with Change in Vis

=>0.5 ddv # of Days with Change in Vis

=>1.0 ddv Maximum Change in Vis (ddv) Great Gulf Base Case All (B 41,42,43 & PB1-4) 73 14 3 1.287 Boilers 41 & 42 61 7 0 0.847 Boiler 43 34 0 0 0.470 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 66 8 0 0.943 Boilers 41 & 42 35 0 0 0.488 SCR & Lime DSI All (B 41,42,43 & PB1-4) 70 12 1 1.186 Boilers 41 & 42 50 4 0 0.774 Boiler 43 27 0 0 0.436 SCR & SDA All (B 41,42,43 & PB1-4) 11 0 0 0.218 Boilers 41 & 42 2 0 0 0.124 Boiler 43 0 0 0 0.091 Dolly Sods Base Case All (B 41,42,43 & PB1-4) 19 4 1 1.205 Boilers 41 & 42 10 1 0 0.763 Boiler 43 7 0 0 0.469 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 12 2 0 0.883 Boilers 41 & 42 7 0 0 0.427 SCR & Lime DSI All (B 41,42,43 & PB1-4) 16 4 1 1.093 Boilers 41 & 42 10 1 0 0.693 Boiler 43 7 0 0 0.422 SCR & SDA All (B 41,42,43 & PB1-4) 1 0 0 0.159 Boilers 41 & 42 0 0 0 0.092 Boiler 43 0 0 0 0.063

### 4



## Eastman Business Park (Continued) Number of Days with Visibility Impa cts (delta deciview ) Above Thresholds Predicted using the Hybrid Meteorological Data Set

Operating Scenario # of Days with Change in Vis

=>0.1 ddv # of Days with Change in Vis

=>0.5 ddv # of Days with Change in Vis

=>1.0 ddv Maximum Change in Vis (ddv) Otter Creek Base Case All (B 41,42,43 & PB1-4) 13 4 1 1.022 Boilers 41 & 42 8 1 0 0.646 Boiler 43 5 0 0 0.396 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 9 1 0 0.749 Boilers 41 & 42 6 0 0 0.364 SCR & Lime DSI All (B 41,42,43 & PB1-4) 10 3 0 0.928 Boilers 41 & 42 8 1 0 0.588 Boiler 43 5 0 0 0.355 SCR & SDA All (B 41,42,43 & PB1-4) 1 0 0 0.134 Boilers 41 & 42 0 0 0 0.078 Boiler 43 0 0 0 0.053Julian Day hr 0

All 1 1.218 78 79.13 19.88 0.36 0.14 0.13 0.36 8 0.54 214 96.39 3.04 0.21 0.08 0.07 0.21 Boilers 41& 42 1 0.798 78 80.60 18.55 0.26 0.13 0.12 0.33 8 0.354 214 96.75 2.77 0.15 0.07 0.06 0.19 Boiler 43 1 0.446 78 76.46 22.29 0.54 0.16 0.15 0.4 8 0.203 329 68.81 29.47 0.73 0.22 0.22 0.55 Package Boilers 1 0.005 78 69.35 29.86 0 0 0.63 0.15 8 0.002 254 79.96 19.23 0 0 0.64 0.17

All 1 0.809 225 96.23 3.30 0.19 0.07 0.04 0.18 8 0.622 168 86.65 12.70 0.27 0.10 0.04 0.24 Boilers 41& 42 1 0.529 225 96.58 3.03 0.13 0.06 0.03 0.16 8 0.402 168 87.70 11.77 0.19 0.09 0.04 0.22 Boiler 43 1 0.291 225 95.57 3.78 0.30 0.09 0.05 0.21 8 0.225 168 84.78 14.36 0.41 0.12 0.05 0.28 Package Boilers 1 0.003 346 70.60 29.18 0 0 0.13 0.1 8 0.002 355 55.75 43.70 0 0 0.32 0.22

All 1 0.915 238 95.08 4.37 0.22 0.08 0.04 0.2 8 0.391 287 91.01 8.42 0.23 0.08 0.04 0.22 Boilers 41& 42 1 0.606 238 95.59 3.96 0.16 0.08 0.04 0.18 8 0.252 287 91.71 7.82 0.16 0.08 0.03 0.2 Boiler 43 1 0.323 238 94.12 5.16 0.35 0.10 0.05 0.23 8 0.142 214 97.78 1.47 0.36 0.10 0.05 0.24 Package Boilers 1 0.004 300 61.90 37.14 0 0 0.76 0.21 8 0.002 214 97.82 1.87 0 0 0.24 0.1

All 1 1.078 252 97.06 2.26 0.26 0.10 0.06 0.25 8 0.467 203 96.33 3.23 0.17 0.06 0.04 0.17 Boilers 41& 42 1 0.709 252 97.40 2.05 0.18 0.09 0.05 0.23 8 0.306 203 96.73 2.91 0.12 0.06 0.03 0.15 Boiler 43 1 0.39 252 96.44 2.66 0.41 0.12 0.07 0.3 8 0.183 30 69.34 29.34 0.59 0.17 0.12 0.44 Package Boilers 1 0.004 252 96.43 3.12 0 0 0.33 0.12 8 0.002 195 87.69 11.91 0 0 0.29 0.1 

## Predicted using the NWS Meteorological Data Set Eastman Business Park Base Case Visibility Impacts (delta deciview)

Presidential Ran g e – Dr y River %

_ PMF L y e Brook Wilderness Area

Acadia National Park

Bri g antine National Wildlife Refu g e NWS 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) %

_ SO4 %

_ NO3 %

_ OC %

_ EC %

_ PMCJulian Day hr 0

All 1 1.069 252 97.10 2.23 0.26 0.10 0.06 0.25 8 0.468 203 96.21 3.35 0.17 0.07 0.04 0.17 Boilers 41& 42 1 0.703 252 97.43 2.02 0.18 0.09 0.05 0.22 8 0.307 203 96.62 3.02 0.12 0.06 0.03 0.15 Boiler 43 1 0.386 252 96.48 2.63 0.40 0.12 0.07 0.3 8 0.192 30 69.17 29.51 0.59 0.17 0.12 0.44 Package Boilers 1 0.004 252 96.49 3.08 0 0 0.33 0.12 8 0.002 195 87.77 11.83 0 0 0.29 0.1

All 1 0.959 221 95.26 3.93 0.32 0.12 0.09 0.29 8 0.315 348 73.74 25.93 0.13 0.05 0.02 0.13 Boilers 41& 42 1 0.619 221 95.84 3.49 0.22 0.10 0.08 0.27 8 0.197 348 75.89 23.85 0.09 0.04 0.02 0.11 Boiler 43 1 0.357 221 94.23 4.70 0.49 0.14 0.10 0.35 8 0.119 239 97.62 1.86 0.24 0.07 0.04 0.17 Package Boilers 1 0.004 221 93.79 5.61 0 0 0.46 0.14 8 0.001 348 63.98 35.86 0 0 0.09 0.05

All 1 0.740 221 95.66 3.55 0.31 0.11 0.08 0.29 8 0.337 348 72.88 26.78 0.14 0.05 0.02 0.13 Boilers 41& 42 1 0.478 222 96.18 3.33 0.17 0.08 0.05 0.20 8 0.209 348 75.10 24.63 0.10 0.04 0.02 0.12 Boiler 43 1 0.276 297 81.79 17.06 0.53 0.15 0.09 0.38 8 0.120 290 83.17 16.25 0.27 0.08 0.04 0.19 Package Boilers 1 0.003 222 93.88 5.71 0 0 0.30 0.10 8 0.001 348 63.00 36.83 0 0 0.10 0.05 Otter Creek 

## Predicted using the NWS Meteorological Data Set (Continued) Eastman Business Park Base Case Visibility Impacts (delta deciview)

% PMC % PMF Great Gulf

Doll y Sods NWS 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) % SO4 % NO3 % OC % ECJulian Day hr 0

All 1 0.916 78 79.99 18.92 0.40 0.15 0.14 0.39 8 0.399 214 96.46 2.91 0.24 0.09 0.08 0.23 Boilers 41& 42 1 0.487 78 83.28 15.77 0.28 0.15 0.13 0.39 8 0.205 183 93.44 5.51 0.31 0.17 0.14 0.43

All 1 0.601 225 96.36 3.11 0.21 0.08 0.04 0.19 8 0.460 168 87.30 11.99 0.30 0.11 0.04 0.26 Boilers 41& 42 1 0.316 253 98.15 1.38 0.16 0.08 0.03 0.20 8 0.241 275 85.06 13.87 0.34 0.18 0.09 0.46

All 1 0.684 238 95.19 4.20 0.25 0.09 0.05 0.22 8 0.294 347 74.30 25.19 0.20 0.07 0.06 0.19 Boilers 41& 42 1 0.367 238 96.14 3.35 0.17 0.09 0.04 0.21 8 0.161 347 78.34 21.20 0.14 0.07 0.06 0.19

All 1 0.808 252 97.20 2.06 0.29 0.11 0.07 0.27 8 0.346 30 73.02 25.83 0.45 0.17 0.11 0.42 Boilers 41& 42 1 0.429 252 97.88 1.52 0.19 0.10 0.06 0.25 8 0.181 203 97.22 2.38 0.12 0.07 0.04 0.17 NWS 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) %

_ SO4 %

_ NO3 %

_ OC %

_ EC %

_ PMC %

_ PMF L y e Brook Wilderness Area

Acadia National Park

Bri g antine National Wildlife Refu g e 

## Predicted using the NWS Meteorological Data Set Eastman Business Park Restricted Case Visibility Impacts (delta deciview)

Presidential Ran g e – Dr y RiverJulian Day hr 0

All 1 0.802 252 97.23 2.04 0.29 0.11 0.07 0.27 8 0.366 30 73.05 25.81 0.45 0.16 0.11 0.42 Boilers 41& 42 1 0.427 252 97.91 1.5 0.19 0.1 0.06 0.25 8 0.181 203 97.13 2.47 0.12 0.07 0.04 0.17

All 1 0.708 221 95.46 3.64 0.35 0.13 0.09 0.32 8 0.232 348 74.69 24.95 0.15 0.05 0.02 0.14 Boilers 41& 42 1 0.359 221 96.69 2.58 0.23 0.12 0.09 0.30 8 0.113 348 79.47 20.23 0.10 0.05 0.02 0.13

All 1 0.545 222 95.84 3.49 0.27 0.10 0.06 0.24 8 0.246 348 73.78 25.84 0.16 0.06 0.02 0.14 Boilers 41& 42 1 0.281 222 96.78 2.68 0.17 0.09 0.06 0.23 8 0.118 348 78.70 20.99 0.10 0.05 0.02 0.14 NWS 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) % SO4 % NO3 % OC % EC

Otter Creek 

## Predicted using the NWS Meteorological Data Set (Continued) Eastman Business Park Restricted Case Visibility Impacts (delta deciview)

% PMC % PMF Great Gulf

Doll y SodsJulian Day hr 0

All 1 1.013 78 92.34 7.08 0.44 0.03 0.03 0.08 8 0.498 214 98.76 0.94 0.23 0.02 0.01 0.04 Boilers 41& 42 1 0.666 78 93.11 6.44 0.32 0.03 0.03 0.07 8 0.319 183 97.37 2.15 0.34 0.03 0.03 0.08 Boiler 43 1 0.363 78 91.19 7.98 0.67 0.03 0.03 0.09 8 0.170 214 98.48 1.08 0.36 0.02 0.02 0.05

All 1 0.751 225 98.73 1.00 0.21 0.01 0.01 0.04 8 0.524 346 92.31 7.30 0.30 0.02 0.01 0.05 Boilers 41& 42 1 0.489 225 98.91 0.90 0.14 0.01 0.01 0.03 8 0.337 346 93.10 6.61 0.21 0.02 0.01 0.05 Boiler 43 1 0.271 225 98.46 1.15 0.32 0.02 0.01 0.04 8 0.190 346 91.21 8.23 0.47 0.02 0.01 0.06

All 1 0.845 238 98.29 1.4 0.24 0.02 0.01 0.04 8 0.355 287 96.95 2.72 0.26 0.02 0.01 0.04 Boilers 41& 42 1 0.561 238 98.51 1.25 0.18 0.01 0.01 0.04 8 0.232 287 97.27 2.48 0.18 0.02 0.01 0.04 Boiler 43 1 0.295 238 97.93 1.62 0.38 0.02 0.01 0.05 8 0.131 260 96.12 3.31 0.47 0.02 0.01 0.06

All 1 1.011 252 98.92 0.72 0.28 0.02 0.01 0.05 8 0.435 203 98.79 0.98 0.18 0.01 0.01 0.03 Boilers 41& 42 1 0.665 252 99.09 0.64 0.20 0.02 0.01 0.04 8 0.286 203 98.96 0.87 0.13 0.01 0.01 0.03 Boiler 43 1 0.364 252 98.63 0.83 0.44 0.02 0.01 0.06 8 0.151 203 98.5 1.14 0.29 0.01 0.01 0.04 

## Predicted using the NWS Meteorological Data Set Eastman Business Park SCR-Lime Case Visibility Impacts (delta deciview)

Presidential Ran g e – Dr y River %

_ PMF L y e Brook Wilderness Area

Acadia National Park

Bri g antine National Wildlife Refu g e NWS 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) %

_ SO4 %

_ NO3 %

_ OC %

_ EC %

_ PMCJulian Day hr 0

All 1 1.002 252 98.94 0.71 0.28 0.02 0.01 0.05 8 0.411 16 90.20 9.20 0.47 0.03 0.02 0.08 Boilers 41& 42 1 0.659 252 99.10 0.63 0.19 0.02 0.01 0.04 8 0.263 16 91.25 8.30 0.33 0.03 0.02 0.08 Boiler 43 1 0.359 252 98.64 0.83 0.43 0.02 0.01 0.06 8 0.149 16 88.71 10.41 0.72 0.04 0.02 0.1

All 1 0.884 221 98.32 1.23 0.34 0.02 0.02 0.06 8 0.271 250 97.67 1.90 0.34 0.02 0.01 0.06 Boilers 41& 42 1 0.569 221 98.61 1.07 0.24 0.02 0.02 0.05 8 0.177 250 97.93 1.75 0.24 0.02 0.01 0.05 Boiler 43 1 0.328 221 97.87 1.49 0.53 0.03 0.02 0.07 8 0.095 250 97.27 2.09 0.54 0.03 0.01 0.07

All 1 0.684 221 98.46 1.11 0.34 0.02 0.02 0.06 8 0.279 239 99.30 0.50 0.16 0.01 0.01 0.03 Boilers 41& 42 1 0.442 222 98.75 1.01 0.18 0.02 0.01 0.04 8 0.184 239 99.40 0.45 0.11 0.01 0.01 0.02 Boiler 43 1 0.253 221 98.03 1.34 0.52 0.03 0.02 0.07 8 0.101 290 94.08 5.54 0.31 0.02 0.01 0.04 Otter Creek 

## Predicted using the NWS Meteorological Data Set (Continued) Eastman Business Park SCR-Lime Case Visibility Impacts (delta deciview)

% PMC % PMF Great Gulf

Doll y Sods NWS 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) % SO4 % NO3 % OC % ECJulian Day hr 0

All 1 0.244 78 66.24 31.16 1.97 0.14 0.14 0.36 8 0.113 253 88.70 8.94 1.81 0.13 0.10 0.32 Boilers 41& 42 1 0.144 78 66.04 31.72 1.59 0.14 0.13 0.37 8 0.064 20 52.26 45.62 1.53 0.14 0.09 0.36 Boiler 43 1 0.097 78 66.34 30.38 2.65 0.14 0.13 0.36 8 0.048 20 54.91 42.06 2.48 0.13 0.08 0.34

All 1 0.136 356 60.85 35.73 2.69 0.18 0.07 0.48 8 0.103 168 76.03 21.91 1.63 0.11 0.05 0.27 Boilers 41& 42 1 0.074 356 57.79 39.09 2.32 0.20 0.07 0.53 8 0.059 168 76.14 22.15 1.28 0.11 0.04 0.27 Boiler 43 1 0.060 356 65.02 31.09 3.24 0.16 0.05 0.43 8 0.044 225 90.79 6.87 1.94 0.10 0.06 0.25

All 1 0.193 300 64.87 32.10 2.34 0.15 0.14 0.4 8 0.070 301 61.14 36.36 1.96 0.13 0.07 0.33 Boilers 41& 42 1 0.107 300 63.74 33.61 1.93 0.16 0.13 0.42 8 0.039 301 60.14 37.75 1.57 0.13 0.07 0.34 Boiler 43 1 0.083 300 66.45 29.93 2.97 0.15 0.12 0.38 8 0.029 347 52.70 45.58 1.41 0.07 0.06 0.18

All 1 0.166 252 93.74 3.97 1.77 0.12 0.08 0.31 8 0.077 225 89.12 8.88 1.54 0.10 0.09 0.27 Boilers 41& 42 1 0.095 252 94.11 3.99 1.39 0.12 0.08 0.31 8 0.044 224 93.94 4.47 1.15 0.10 0.07 0.26 Boiler 43 1 0.067 252 93.06 4.00 2.41 0.12 0.08 0.32 8 0.030 225 88.26 9.12 2.14 0.11 0.08 0.29 

## Predicted using the NWS Meteorological Data Set Eastman Business Park SCR-SDA Case Visibility Impacts (delta deciview)

Presidential Ran g e – Dr y River %

_ PMF L y e Brook Wilderness Area

Acadia National Park

Bri g antine National Wildlife Refu g e NWS 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) %

_ SO4 %

_ NO3 %

_ OC %

_ EC %

_ PMCJulian Day hr 0

All 1 0.164 252 93.81 3.93 1.75 0.12 0.08 0.31 8 0.077 224 93.49 4.57 1.49 0.10 0.08 0.27 Boilers 41& 42 1 0.094 252 94.18 3.94 1.37 0.12 0.07 0.31 8 0.046 224 93.83 4.57 1.16 0.10 0.08 0.26 Boiler 43 1 0.066 252 93.12 3.97 2.40 0.12 0.08 0.32 8 0.031 48 67.23 29.01 3.09 0.16 0.11 0.41

All 1 0.148 221 90.95 6.45 2.01 0.13 0.11 0.34 8 0.050 304 61.07 35.42 2.75 0.18 0.10 0.48 Boilers 41& 42 1 0.084 221 91.43 6.39 1.59 0.14 0.10 0.35 8 0.028 250 86.47 11.50 1.50 0.13 0.07 0.32 Boiler 43 1 0.061 221 90.14 6.59 2.69 0.13 0.10 0.35 8 0.020 348 52.79 45.87 1.12 0.06 0.02 0.15

All 1 0.111 221 91.61 5.82 1.98 0.13 0.11 0.34 8 0.055 348 53.88 45.1 0.8 0.05 0.03 0.14 Boilers 41& 42 1 0.063 221 92.12 5.73 1.57 0.13 0.10 0.34 8 0.032 296 76.29 21.44 1.66 0.14 0.10 0.37 Boiler 43 1 0.046 221 90.76 6.00 2.67 0.13 0.10 0.34 8 0.022 348 51.82 46.81 1.14 0.06 0.02 0.15 Otter Creek 

## Predicted using the NWS Meteorological Data Set (Continued) Eastman Business Park SCR-SDA Case Visibility Impacts (delta deciview)

% PMC % PMF Great Gulf

Doll y Sods NWS 2002 % of Modeled Extinction by Species

Rank Change in Vis (ddv) % SO4 % NO3 % OC % EC

## Eastman Business Park Number of Days with Visibility Impa cts (delta deciview ) Above Thresholds Predicted using the VT-NWS Meteorological Data Set

Operating Scenario # of Days with Change in Vis

=>0.1 ddv # of Days with Change in Vis

=>0.5 ddv # of Days with Change in Vis

=>1.0 ddv Maximum Change in Vis (ddv) Lye Brook Wilderness Area Base Case All (B 41,42,43 & PB1-4) 112 10 1 1.218 Boilers 41 & 42 68 1 0 0.798 Boiler 43 39 0 0 0.446 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 51 5 0 0.916 Boilers 41 & 42 39 0 0 0.487 SCR & Lime DSI All (B 41,42,43 & PB1-4) 92 7 1 1.013 Boilers 41 & 42 60 1 0 0.666 Boiler 43 27 0 0 0.363 SCR & SDA All (B 41,42,43 & PB1-4) 12 0 0 0.244 Boilers 41 & 42 2 0 0 0.144 Boiler 43 0 0 0 0.097 Acadia National Park Base Case All (B 41,42,43 & PB1-4) 81 11 0 0.809 Boilers 41 & 42 47 1 0 0.529 Boiler 43 27 0 0 0.291 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 52 4 0 0.601 Boilers 41 & 42 28 0 0 0.316 SCR & Lime DSI All (B 41,42,43 & PB1-4) 70 9 0 0.751 Boilers 41 & 42 39 0 0 0.489 Boiler 43 21 0 0 0.271 SCR & SDA All (B 41,42,43 & PB1-4) 8 0 0 0.136 Boilers 41 & 42 0 0 0 0.074 Boiler 43 0 0 0 0.060

### 2



## Eastman Business Park (Continued) Number of Days with Visibility Impa cts (delta deciview ) Above Thresholds Predicted using the VT-NWS Meteorological Data Set

Operating Scenario # of Days with Change in Vis

=>0.1 ddv # of Days with Change in Vis

=>0.5 ddv # of Days with Change in Vis

=>1.0 ddv Maximum Change in Vis (ddv) Brigantine National Wildlife Refuge Base Case All (B 41,42,43 & PB1-4) 55 6 0 0.915 Boilers 41 & 42 30 3 0 0.606 Boiler 43 15 0 0 0.323 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 37 3 0 0.684 Boilers 41 & 42 15 0 0 0.367 SCR & Lime DSI All (B 41,42,43 & PB1-4) 43 5 0 0.845 Boilers 41 & 42 21 1 0 0.561 Boiler 43 11 0 0 0.295 SCR & SDA All (B 41,42,43 & PB1-4) 4 0 0 0.193 Boilers 41 & 42 1 0 0 0.107 Boiler 43 0 0 0 0.083 Presidential Range – Dry River Base Case All (B 41,42,43 & PB1-4) 66 7 1 1.078 Boilers 41 & 42 33 3 0 0.709 Boiler 43 18 0 0 0.390 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 43 4 0 0.808 Boilers 41 & 42 17 0 0 0.429 SCR & Lime DSI All (B 41,42,43 & PB1-4) 54 4 1 1.011 Boilers 41 & 42 24 2 0 0.665 Boiler 43 12 0 0 0.364 SCR & SDA All (B 41,42,43 & PB1-4) 4 0 0 0.166 Boilers 41 & 42 0 0 0 0.095 Boiler 43 0 0 0 0.067

### 3



## Eastman Business Park (Continued) Number of Days with Visibility Impa cts (delta deciview ) Above Thresholds Predicted using the VT-NWS Meteorological Data Set

Operating Scenario # of Days with Change in Vis

=>0.1 ddv # of Days with Change in Vis

=>0.5 ddv # of Days with Change in Vis

=>1.0 ddv Maximum Change in Vis (ddv) Great Gulf Base Case All (B 41,42,43 & PB1-4) 58 7 1 1.069 Boilers 41 & 42 31 2 0 0.709 Boiler 43 15 0 0 0.386 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 41 4 0 0.802 Boilers 41 & 42 16 0 0 0.427 SCR & Lime DSI All (B 41,42,43 & PB1-4) 45 6 1 1.022 Boilers 41 & 42 25 1 0 0.659 Boiler 43 13 0 0 0.359 SCR & SDA All (B 41,42,43 & PB1-4) 3 0 0 0.164 Boilers 41 & 42 0 0 0 0.094 Boiler 43 0 0 0 0.066 Dolly Sods Base Case All (B 41,42,43 & PB1-4) 28 3 0 0.959 Boilers 41 & 42 17 1 0 0.619 Boiler 43 9 0 0 0.357 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 19 2 0 0.708 Boilers 41 & 42 10 0 0 0.359 SCR & Lime DSI All (B 41,42,43 & PB1-4) 25 3 0 0.884 Boilers 41 & 42 15 1 0 0.569 Boiler 43 7 0 0 0.328 SCR & SDA All (B 41,42,43 & PB1-4) 3 0 0 0.148 Boilers 41 & 42 0 0 0 0.084 Boiler 43 0 0 0 0.061

### 4



## Eastman Business Park (Continued) Number of Days with Visibility Impa cts (delta deciview ) Above Thresholds Predicted using the VT-NWS Meteorological Data Set

Operating Scenario # of Days with Change in Vis

=>0.1 ddv # of Days with Change in Vis

=>0.5 ddv # of Days with Change in Vis

=>1.0 ddv Maximum Change in Vis (ddv) Otter Creek Base Case All (B 41,42,43 & PB1-4) 27 3 0 0.740 Boilers 41 & 42 17 0 0 0.478 Boiler 43 9 0 0 0.276 Restricted B41 or B42 All (B 41,42,43 & PB1-4) 19 2 0 0.545 Boilers 41 & 42 10 0 0 0.281 SCR & Lime DSI All (B 41,42,43 & PB1-4) 22 3 0 0.684 Boilers 41 & 42 14 0 0 0.442 Boiler 43 8 0 0 0.253 SCR & SDA All (B 41,42,43 & PB1-4) 3 0 0 0.111 Boilers 41 & 42 0 0 0 0.063 Boiler 43 0 0 0 0.046