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

C:\Documeirts and Settinss\196142[-ocal Seftins\Tenrporarv Internet Files\Coilted.Outlook\T0PV7UBD\BART Coverletter.doc
3800 DercyAvenue, Suite 325

Rochester, NY 14616

58S5886982

585-588-4'550 fa<

SIIEZ-DEG S of Rocftesfer

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 Technology 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 Contents 
2846/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) Predicted using the VT-NWS Meteorological Data 

Set

Table 2-5 Visibility Impacts (delta deciview) Predicted 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 Retrofit 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 designed 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 identified 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 visibility impairing pollutant 

[including sulfur dioxide (SO2), oxides of nitrogen (NOx), particulate matter (PM10), and 

volatile organic compounds (VOCs)]. 

The U.S. EPA BART Guidelines provide general recommendations for conducting BART 

assessments, but essentially leave it up to the individual states to determine the approach to 

be taken in the visibility assessment and the associated 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 recommendations of EPA in their approach. 

The federal rule lists five steps for a BART analysis: 

STEP 1—Identify All Available Retrofit Control Technologies, 

STEP 2— Eliminate Technically Infeasible Options, 

STEP 3— Evaluate Control Effectiveness of Remaining Control Technologies, 

STEP 4— Evaluate Impacts and Document the Results, and 

STEP 5—Evaluate Visibility Impacts. 

New York specifies a 5-Factor BART analysis 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 control of regional haze precursors, specifically: 

sulfur dioxide (SO2), nitrogen oxides (NOx), 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 County, 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 Kodak 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 treatment) 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 (NYSDEC # 8-2614-00205/01827) was issued for the 

purpose of designating SUEZ-Duke Energy Generation 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 operates two steam and electric generating 

stations at Eastman Business Park (EBP). The primary 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 EPA’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 EPA’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 NOx and SO2 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 approximately 1.5 miles to the east of Building 

321. Four BART-eligible oil-fired package boilers 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 Tables 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 impairing 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 significantly lower stack heights for 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 combination 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 owns and operates multiple small BART-eligible sources of 

SO2, NOx and PM associated with Kodak manufacturing operations. The BART 

determination for these sources has been submitted to the NYSDEC under separate cover 

(Letter from Michael Zapkin, Kodak to Robert 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 requirements 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 NOx 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 technologies and eliminates technically infeasible 

control options; 

Section 4 evaluates control effectiveness of remaining control technologies; 

Section 5 evaluates impacts using the five-factor 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 Calculations, and Appendix B provides air quality 

modeling documentation. 

2846/BART Analysis 9-29.doc 1-4 Introduction 
Eastman Business Park BART Analysis Rochester, New York
Weiland 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 VISIBILITY IMPAIRMENT 

NYSDEC has developed a modeling protocol (dated 2/25/10) based on discussions with the 

involved agencies, including EPA Region 2, Vermont Department of Environmental 

Conservation (VTDEC), and the Federal Land Managers (FLMs) for Class I areas. In the 

protocol, NYSDEC defines a set of default recommendations 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 their 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 would be typical of most facilities. We 

recommend that States use the 24 hour average actual emission rate from 

the highest emitting day of the meteorological period modeled, unless this 

rate reflects periods start-up, shutdown, or malfunction. 

The document NYSDEC Guidance and Protocol for Visibility 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 (NOx): For Boilers 41, 42 and 43, historical Continuous Emissions 

Monitoring System (CEMS) data were queried for the highest NOx mass emissions for 

calendar years 2005-2009. Those were cross-checked against the reported data in EPA’s 

Clean Air Markets Division (CAMD) online database 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 Contribution to Visibility Impairment 
2846/BART Analysis 9-29.doc 2-2 Contribution to Visibility Impairment 

Sulfur Dioxide (SO2): For Boilers 41, 42 and 43, coal sulfur content is tracked by shipment; 

and that coal is burned for a predictable number of days after the shipment arrives. 

Maximum 24-hour SO2 emission rates were calculated based on the highest coal-fired heat 

input rate during the days when the highest 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 condensable 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 website1 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 Particulate Matter Inorganic, and Condensable 

Particulate Matter Organic.” These are entered into the modeling in the following 

categories: “Coarse, Fine, Elemental Carbon, Sulfates, and Organic Carbon.” The 

spreadsheet for cyclone furnaces with electrostatic 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 SO2, 0.57 lb/MMBtu NOx, 

0.1 lb MMBtu filterable PM), plus the EPA AP-42 factor for condensable PM from oil 

combustion (0.01 lb/MMBtu). These are converted 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 NOx SO2 PM10 

PM 

Fine 

Elemental 

Carbon SO4 

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 4.07 0.16 7.37 1.84 

Package Boilers (1-4) 0.98 2.81 0.172 0.017 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 guideline 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 meteorological data and incorporates complex terrain 

algorithms, chemical transformations, building 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 maximum 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 assessed in the following Class I areas: Lye Brook Wilderness Area 

in VT, Acadia National Park in ME, Brigantine 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 receptors sets are of sufficient density to be 

used for the CALPUFF visibility modeling. The coordinates of each receptor were 

converted to Lambert Conformal Conic projections 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. Both 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 Contribution 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 computed 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 concentrations in the chemical transformation 

scheme (conversion of SO2 to SO4 and NOx to HNO3 and NO3). 

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 Contribution 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. The NYSDEC protocol recommends the use of 

CALPOST Version 6.221 (Method 8, Mode 5) which performs the correct calculations with 

the latest EPA/FLM recommendations using 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) Predicted using the VT-NWS Meteorological Data 

Set 

VT-NWS 2002 % of Modeled Extinction by Species 

 Rank 

Change 

in Vis 

(ddv)

Julian 

Day 

hr 0 % SO4 % NO3 % 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 Contribution to Visibility Impairment 
Table 2-4 Visibility Impacts (delta deciview) Predicted 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 % SO4 % NO3 % 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 Contribution to Visibility Impairment 
Table 2-5 Visibility Impacts (delta deciview) Predicted using the Hybrid Meteorological Data 

Set 

Hydrid 2002 % of Modeled Extinction by Species 

 Rank 

Change 

in Vis 

(ddv)

Julian 

Day 

hr 0 % SO4 % NO3 % 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 Contribution to Visibility Impairment 
Table 2-5 Visibility Impacts (delta deciview) Predicted using the Hybrid Meteorological Data 

Set (Continued) 

Hydrid 2002 % of Modeled Extinction by Species 

 Rank 

Change 

in Vis 

(ddv)

Julian 

Day 

hr 0 % SO4 % NO3 % 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 Contribution to Visibility Impairment 
!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

Rochester

Syracuse

Springfield

Worcester

Manchester

!! Pittsburgh

PA

NJ

NY

MD

DE

WV

Dolly Sods VA

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 SO2 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, the sulfur content of coal fired in the boiler may be 

lowered 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 SO2 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 characteristics. 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 SO2 in flue gas can be removed by reacting the sulfur compounds with a solution of water and an 

alkaline chemical to form insoluble salts that are removed in the scrubber effluent... Most wet FGD 

systems for control of SO2 emissions from coal-fired electric utility 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., sodium 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 SO2

emissions from coal-fired electric utility boilers. Limestone sorbent is inexpensive and generally available 

throughout the United States. In a wet limestone scrubber, the flue gas containing SO2 is brought into 

contact with limestone/water slurry. The SO2 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 SO2 is contacted with hydrated lime/water slurry; the SO2 is absorbed into the slurry 

and reacts with hydrated lime to form an insoluble sludge. The hydrated lime provides greater alkalinity 

(higher pH) and reactivity than limestone. However, lime-scrubbing processes require appropriate disposal 

of large quantities of waste sludge. The SO2 removal efficiencies of existing wet limestone scrubbers range 

from 31 to 97 percent, with an average of 78 percent. The SO2 removal efficiencies of existing wet lime 

2846/BART Analysis 9-29.doc 3-1 Technically Feasible Control Technologies 
scrubbers range from 30 to 95 percent. For both types of wet scrubbers, operating parameters affecting SO2

removal efficiency include liquid-to-gas ratio, pH of the scrubbing medium, and the ratio of calcium 

sorbent to SO2. Periodic maintenance is needed because of scaling, erosion, and plugging problems. Recent 

advancements include the use of additives or design changes to promote SO2 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 the 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-proposed, Kodak may need to install 

activated carbon injection (ACI) for mercury and dioxin control. The presence of 

activated carbon in the flyash or the scrubber 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 NOx 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 

SO2 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 temperatures are in the range of 120 to 180 °C 

(250 to 350 °F). The SO2 is absorbed in the slurry and reacts with the hydrated lime reagent to form solid 

calcium sulfite and calcium sulfate as in a wet lime scrubber. The water is evaporated by the hot flue gas 

and forms dry, solid particles containing the reacted sulfur. These particles are entrained in the flue gas, 

along with fly ash, and are collected in a PM collection device. Most of the SO2 removal occurs in the 

spray dryer vessel itself, although some additional SO2 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 SO2 removal are the calcium-reagent-to-sulfur stoichiometric 

ratio and the approach to saturation in the spray dryer. To increase overall sorbent use, the solids collected 

in the spray dryer and the PM collection device may be recycled. The SO2 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 downstream of the existing ESP. A new fabric filter 

would be installed downstream of the spray dryer 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 Technically 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 another 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 SO2 is 

adsorbed and reacts with the powdered sorbent. The dry solids are entrained in the combustion gas stream, 

along with fly ash, and collected by the PM control device. The SO2 removal efficiencies of existing dry 

injection systems range from 40 to 60 percent.

Dry injection is feasible for retrofit on Boilers 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 particulate 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% SO2 removal for these units. Another suitable sorbent is trona 

(trisodium hydrogendicarbonate dehydrate), a naturally-occurring mineral. Trona SO2

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. Characteristics 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 sorbate 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 SO2 removal efficiencies for CFBA technologies range from 80 to 98 percent, providing a very 

effective means of control.

For this retrofit application, CFBA would likely achieve similar SO2 removal to a wet FGD 

system or spray dryer absorber. Since a CFBA 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-NOx burners (LNBs), overfire air, offstoichiometric firing, selective or biased burner firing, reburning, and burners-out-of-service. Control of 

NOx also can be achieved through staged combustion (also 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 Technically Feasible Control Technologies 
staging lowers the peak flame temperature, thereby reducing thermal NOx, and lowering the production of 

fuel NOx 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- NOx 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 NOx burners and air staging. Low-NOx burners may be used to 

lower NOx emissions by about 25 to 55 percent. Use of overfire air (OFA) as a single NOx control 

technique reduces NOx by 15 to 50 percent. When OFA is combined with low- NOx burners, reductions of 

up to 60 percent may result. The actual NOx 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 fuel injected downstream 

may not necessarily be the same as that used in the primary 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 NOx 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 flame temperature and the concentration of oxygen in the primary 

combustion zone are reduced. Increasing the space between burners provides greater heat transfer to heatabsorbing surfaces. Another combustion control technique involves reducing the boiler load. In this case, 

the formation of thermal NOx generally decreases directly with decreases in heat release rate; however, 

reducing the load may cause poor air and fuel mixing and increase CO and soot emissions.

Boilers 41, 42 and 43 already use combustion controls to the extent feasible. These boilers 

are cyclone boilers, which “precludes the use of low-NOx burners and air staging.” Natural 

gas is already being used as a reburn fuel to reduce NOx emissions. 

Selective Catalytic Reduction 

The selective catalytic reduction (SCR) process uses a catalyst with ammonia gas (NH3) to reduce the NO 

and NO2 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 reactions 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 the 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 added for the ammonia injection 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 associated ductwork. In some cases, 

the boiler must be modified to increase the economizer exit temperature to the 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 SO2 in the flue gas to produce SO3. The SO3 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 combination of ammonia slip and increased SO3 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 visible plume, the so-called “blue plume”.

Selective catalytic reduction is technically feasible for Boilers 41, 42 and 43. Complicating 

factors are as follows: 

2846/BART Analysis 9-29.doc 3-4 Technically Feasible Control Technologies 
Significant boiler modifications may be needed for SCR to operate in the correct 

temperature window. 

The SO2 to SO3 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 NO2 in the flue gas to molecular nitrogen and water but does not require the use of a catalyst to 

prompt these reactions. Instead, the reducing agent is injected into the flue gas stream at a point where the 

flue gas temperature is within a very specific temperature range. Currently, two SNCR processes are 

commercially available: the THERMAL DeNOx and the NOxOUT (USEPA, 1998). The THERMAL 

DeNOx 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 NOx 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 NOxOUT is a similar process but uses an aqueous urea solution as 

the reagent in place of ammonia. Using nitrogen-based reagents requires operators of SNCR systems to 

closely monitor and control the rate of reagent injection. If injection rates are too high, NOx emissions may 

increase, and stack emissions of ammonia 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-specific, 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 moderate effectiveness. The SNCR retrofit would have the 

same ammonia safety and ammonia salts problems 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 collection efficiencies (greater than 99 percent), but at 

the cost of increased unit size. An ESP operates by imparting an electrical charge to incoming particles, and 

then attracting the particles to oppositely charged metal 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 depends 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. Low-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 Technically Feasible Control Technologies 
sizes. 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 efficiency to 80 to 95 percent. 

An ESP can be used at one of two locations in a coal-fired electric utility boiler system. For many years, 

every ESP was installed downstream of the air heater where the temperature 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 SO2 emission requirements, many electric utilities switched to burning low-sulfur coal (discussed 

in Section 2.3.2 under SO2 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 are 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 installed. The control options being considered 

involve maintaining those existing ESPs in-service. Due to location and breeching 

configuration there is not enough space to allow 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 control 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 surface 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 trapped on the cake surface. The fabric material used is typically fabricated in the 

shape of long, cylindrical bags. Hence, fabric filters also are frequently 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 design 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 boiler 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) involves a modified fabric filter that uses electrostatic 

charging of incoming dust particles to increase collection efficiency and reduce pressure drop compared to 

fabric filters without charging. Filter bags are specially made to include wires or conductive threads, which 

produce an electrical field 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 the field and are charged, they 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 Technically Feasible Control Technologies 
2846/BART Analysis 9-29.doc 3-7 Technically Feasible Control Technologies 

agglomeration increases efficiency of small particle collection. Cleaning is required less frequently, 

resulting in longer bag life. For felted or nonwoven bags, the field promotes collection on the outer surface 

of the fabric, which also promotes longer bag life. Filtration velocity can be increased so that less fabric 

area is required in the baghouse. The amount of reduction 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 Boilers 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 dry injection system (or spray dryer absorber) 

that includes ACI could control SO2, 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 similar 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 entail higher operating costs associated with achieving 

high collection efficiency, they are not widely used in the industry. Similarly, 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 operating restriction where only two of the three 

coal-fired cyclone boilers would operate at any one time (the Restricted Operation case). 

This would result in approximately one-third reduction of SO2, NOx, and particulate matter 

when compared to the full load case. To be feasible, such a restriction would need to allow 

one boiler to ramp up while another is shutting 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 intent 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 Analysis 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 SO2, NOx, and particulate matter by about onethird;.

2) Lime dry injection: reduction of SO2 by 5%;

3) Trona dry injection: reduction of SO2 by 70%;

4) Spray dryer absorber: reduction of SO2 by 90%;

5) Wet flue gas desulfurization: reduction of SO2 by 90%;

6) Selective non-catalytic reduction: reduction of NOx by 35%;

7) Selective catalytic reduction: reduction of NOx by 70%; and

8) Fabric filtration: reduction of the filterable portion of particulate matter to 0.02 

pounds per million Btu.

Some technologies will provide some collateral control of other pollutants; for example, 

SO2 control technologies can also remove some particulate 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 Effectiveness 
2846/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 techniques in the EPA Control Cost Manual as 

recommended in 40 CFR 51 Appendix Y, supplemented by vendor data for SO2 and PM 

control options, and supplemented by Kodak and 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 significantly different prior to 2007 (with three other large boilers 

operating onsite), so the most recent three year 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 the 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 rate when calculating the tons removed: 

Annualized cost of control

(Restricted Operation emission rate – controlled emission rate) 

The baseline and Restricted Operation emission 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 Restricted Operation Emissions, ton/year 

SO2 11,998 9,843 

NOx 2,449 1,969 

Particulate matter* 619 544 

* includes filterable and condensable particulate matter. 

 

2 Note that the baseline for cost estimation is different from the baseline for modeling; per NYSDEC guidance, baseline 

modeling uses the highest actual 24-hour average 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) 

Dry lime injection & fabric $8,732 SO2 $9,947 SO2

filtration $5,238,187 $10,578 PM $11,255 PM 

Dry trona injection & fabric $3,487 SO2 $3,545 SO2

filtration $29,286,852 $107,530 PM $102,104 PM 

Spray dryer absorber & $1,406 SO2 $1,597 SO2

fabric filtration $15,184,149 $55,750 PM $59,135 PM 

$1,482 SO2 $1,745 SO2

Wet FGD & fabric filtration $16,006,954 $58,771 PM $64,614 PM 

SNCR $1,817,144 $2,120 NOx $2,564 NOx 

SCR $3,780,977 $2,206 NOx $2,688 NOx 

Supporting calculations are presented in Appendix 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 final 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 neighbors 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 project that addresses BART, RACT, and NESHAP 

compliance. Therefore, in addition to the restricted operation case the model cases in this 

analysis include the following retrofit combinations: 

SCR, lime dry injection, and fabric filtration; and 

SCR, spray dryer absorber, and fabric filtration. 

The results of the visibility modeling analysis are presented in detail in Section 6, below. 

Comparing to the maximum 98th 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 (presented 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 Analysis 
2846/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 visibility improvements, and therefore under-predicts 

the dollars-per-deciview cost of control. 
6.0 VISIBILITY ANALYSIS 

This section presents the CALPUFF visibility modeling analysis to demonstrate the expected 

net improvement in visibility for 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 emissions are conservatively calculated based on 

shutting off the least-polluting of the three cyclone boilers for each pollutant. For 

particulate matter, fabric filter control efficiency is weighted towards coarse particulate, as 

fabric filters are more effective in removing 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 for 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 National Park in ME, Brigantine Wildlife Refuge 

in NJ, Presidential Range and Great Gulf Wilderness Areas in NH, and Dolly Sods and Otter 

Creek Wilderness Areas in WV. 

The CALPUFF net visibility modeling was run including Boilers 41, 42, 43 and the four oilfired package boilers at Eastman Business Park using maximum daily emission rates of SO2, 

NOx 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 output. The FLMs have recommended the use of 

CALPOST Version 6.221 (Method 8, Mode 5) which performs the correct calculations with 

the latest EPA/FLM recommendations using 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 single year of meteorological data. 

The analysis follows the NYSDEC recommendation for CALPUFF post-processing of specific 

visibility impacts to assist in their determination of the best BART alternative for each 

source, namely: 

1) the maximum and 98% (or 8th highest) 24 hour 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 and 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 the individual contribution of SOx, NOx 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 8th 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 corresponding 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 %_SO4 %_NO3 %_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 for 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 Analysis 
2846/BART Analysis 9-29.doc 6-4 Visibility Analysis 

Table 6-3 Number of Days Exceeding 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 Operating 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 smaller than the equivalent 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 product prices, the market share, and 

profitability of the source.” Kodak and SDEGS 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 visibility change of 0.5 deciview if the 98th

percentile worst-case meteorology happened at the same day as each boiler emitted 

each individual pollutant at its worst-case emission rate, and on a day with top 20% 

background visibility conditions. This combination of events is very unlikely to ever 

happen. Even if it did, a perceptible visibility 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 include3: 

o Omaha Public Power District (OPPD) Nebraska 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/Haze 
2846/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 Environmental 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 review, and to discussing BART further. 
Appendix A 

Supporting Calculations 
KODAK 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

Annualized Cost of

Control

$8,732 /ton SO2 $9,947 /ton SO2

$10,578 /ton PM $11,255 /ton PM

$3,487 /ton SO2 $3,545 /ton SO2

$107,530 /ton PM $102,104 /ton PM

$1,406 /ton SO2 $1,597 /ton SO2

$55,750 /ton PM $59,135 /ton PM

$1,482 /ton SO2 $1,745 /ton SO2

$58,771 /ton PM $64,614 /ton PM

SNCR $1,817,144 $2,120 /ton NOx $2,564 /ton NOx 

SCR $3,780,977 $2,206 /ton NOx $2,688 /ton NOx 

Visibility analysis

Technology Combination

Modeled impact, 

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

Annualized 

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

544
Kodak Park

Control Cost Analysis

9/26/2010

System operation 5397 5397 5397 5397 hours/year

507,714 507,714 507,714 507,714 ACFM airflow

Direct 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 Flemin

$0 $0 $475,899 $475,899 New electric utility bus (double-ended load center)(W 

$482,182 $482,182 $482,182 $482,182 Stack liner (Pennguard Block, W Fleming 9-13 ema

$40,000 $40,000 $40,000 $40,000 SO2 emission monitor (consultant estimate)

$0 $0 $0 $215,872 wastewater pretreatment & sludge thickening (EPA 

$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/curreFreight 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 complianTotal 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 $87,314,617

5% SO2 reduction with 

dry lime injection

70% SO2 reduction with 

Trona

90% SO2 Reduction w/ 

WFGD

90% SO2 Reduction w/SDA 

or CDS

Kodak BART Appendix A.xls SO2 & PM baseline Page 2 of 13
Kodak Park

Control Cost Analysis

9/26/2010

5% SO2 reduction with 

dry lime injection

70% SO2 reduction with 

Trona

90% SO2 Reduction w/ 

WFGD

90% SO2 Reduction w/SDA 

or CDS

Annual CostsOperating labor requirement 8.0 8.0 8.0 8.0 hour/shift per OAQPS Section 6 Table 2.9

hourly 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 maintenance 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, Fan & Pump power 183.8 183.8 1102.8 551.4 0.000181*ACFM*pressure drop, per OAQPS SectioElectric 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 concentration

0 0 49 222 gal/min

water 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 generated 0 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 reagent

3900 49920 19938 12333 pounds per hour

$25 $25 $25 $25 $/ton 

solid 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 (O

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 SO2

619 619 619 619 tons/year PM

5% 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 

$10,578 $107,530 $55,750 $58,771 dollars-per-ton average cost of control for PM re

Kodak BART Appendix A.xls SO2 & PM baseline Page 3 of 13
Kodak Park

Control Cost Analysis

9/26/2010

System operation 5397 5397 hours/year

507,714 507,714 ACFM airflow

Direct 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 $1,868,000 ID fans (W Fleming email 8-30)

$50,000 $50,000 ductwork 

$0 $475,899 New electric utility bus (double-ended load center)

$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 cost Incl. 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 $4,236,846 OAQPS 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 $26,642,745

Selective Non-Catalytic 

Reduction Selective Catalytic Reduction

Kodak BART Appendix A.xls NOx baseline Page 4 of 13
Kodak Park

Control Cost Analysis

9/26/2010

Selective Non-Catalytic 

Reduction Selective Catalytic Reduction

Annual Costsmaintenance cost 0.015 $215,131 0.015 $399,641 OAQPS Eq. 1.21, 2.46

Reagent quantity 44.28 273.7 gallon/hour (SNCR scaled from OAQPS pg1-41, SReagent 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 $/kWhr Electricity 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 $/ton 

solid 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 year

total 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 7total Indirect Annual Costs $1,353,745 $2,514,809total annualized cost $1,817,144 $3,780,977Emissions before control 2449 2449 tons/year NOx 

35% 70% NOx removal

857.0917 1714.18 tons NOx removed

$2,120 $2,206 dollars-per-ton cost effectiveness for NOx rem

Kodak BART Appendix A.xls NOx baseline Page 5 of 13
Kodak Park

Control Cost Analysis

9/26/2010

System operation 4312 4312 4312 4312 hours/year

507,714 507,714 507,714 507,714 ACFM airflow

Direct 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 Flemin

$0 $0 $475,899 $475,899 New electric utility bus (double-ended load center)(W 

$482,182 $482,182 $482,182 $482,182 Stack liner (Pennguard Block, W Fleming 9-13 ema

$40,000 $40,000 $40,000 $40,000 SO2 emission monitor (consultant estimate)

$0 $0 $0 $215,872 wastewater pretreatment & sludge thickening (EPA 

$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/curreFreight 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 complianTotal 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. 2.6.1.2

5% SO2 reduction with 

dry lime injection

70% SO2 reduction with 

Trona

90% SO2 Reduction w/ 

WFGD

90% SO2 Reduction w/SDA 

or CDS

Kodak BART Appendix A.xls SO2 & PM Incremental Page 6 of 13
Kodak Park

Control Cost Analysis

9/26/2010

5% SO2 reduction with 

dry lime injection

70% SO2 reduction with 

Trona

90% SO2 Reduction w/ 

WFGD

90% SO2 Reduction w/SDA 

or CDS

Total Capital Investment (TCI) = DC + IC $26,282,291 $34,120,287 $66,811,216 $87,314,617Annual CostsOperating labor requirement 8.0 8.0 8.0 8.0 hour/shift per OAQPS Section 6 Table 2.9

hourly 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 maintenance 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, Fan & Pump power 183.8 183.8 1102.8 551.4 0.000181*ACFM*pressure drop, per OAQPS SectioElectric 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 concentration

0 0 49 222 gal/min

water 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 generated 0 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 reagent

3900 49920 19938 12333 pounds per hour

$25 $25 $25 $25 $/ton 

solid 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 (O

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 SO2

544 544 544 544 tons/year PM

5% 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 

$11,255 $102,104 $59,135 $64,614 dollars-per-ton average cost of control for PM re

Kodak BART Appendix A.xls SO2 & PM Incremental Page 7 of 13
Kodak Park

Control Cost Analysis

9/26/2010

System operation 4312 4312 hours/year

507,714 507,714 ACFM airflow

Direct 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 $1,868,000 ID fans (W Fleming email 8-30)

$50,000 $50,000 ductwork 

$0 $475,899 New electric utility bus (double-ended load center)(W F

$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 cost Incl. 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 $4,236,846 OAQPS 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 $26,642,745

Selective Non-Catalytic 

Reduction

Selective Catalytic 

Reduction

Kodak BART Appendix A.xls NOx Incremental Page 8 of 13
Kodak Park

Control Cost Analysis

9/26/2010

Selective Non-Catalytic 

Reduction

Selective Catalytic 

Reduction

Annual 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 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 $/kWhr Electricity 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 year

total 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% intotal Indirect Annual Costs $1,353,745 $2,514,809total annualized cost $1,767,394 $3,706,045Emissions before control 1969 1969 tons/year NOx 

35% 70% NOx removal

689.267 1378.53 tons NOx removed

$2,564 $2,688 dollars-per-ton cost effectiveness for NOx removal

Kodak BART Appendix A.xls NOx Incremental Page 9 of 13
SNCR 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 13
SCR 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 13
KODAK PARK

BART Control Cost Baselineaj/Epsilon 9/26/10

Total Source

41 42 43

2007 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 CAMD

NOx Baseline, tons/year: 2,448.8

2007 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 reports

SO2 Baseline, tons/year: 11,997.7

2007 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 reports

PM10 Baseline, tons/year: 619.0

PM10 includes filterable and condensable emissions

Average

2007 hours 3425 6630 5705 52532008 hours 3414 7477 7583 61582009 hours 2930 6129 5281 4780

Hours/year, average: 5,397

Boiler
KODAK PARK

BART Control Cost Restricted Optionaj/Epsilon 9/26/10

Total Source

41 42 43

2007 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 CAMD

NOx Restricted Option, tons/year: 1,969.3

2007 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 reports

SO2 Restricted Option, tons/year: 9,842.7

2007 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 reports

PM10 Restricted Option, tons/year: 543.7

Assume PM10 is filterable-only

Average

2007 hours 0 6630 5705 41122008 hours 0 7477 7583 50202009 hours 0 6129 5281 3803

Hours/year, Retricted Option, average: 4,312

Boiler
 Appendix B 

Air Quality Dispersion Modeling Supporting Documentation 
Julian 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 Range – Dry River

%_PMF

Lye Brook Wilderness Area

Acadia National Park

Brigantine National Wildlife Refuge

Hybrid 2002 % of Modeled Extinction by Species 

Rank

Change in 

Vis (ddv) %_SO4 %_NO3 %_OC %_EC %_PMC
Julian 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

Dolly Sods

Hybrid 2002 % of Modeled Extinction by Species

Rank

Change in 

Vis (ddv) % SO4 % NO3 % OC % EC 
Julian 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 Range – Dry River

%_PMF

Lye Brook Wilderness Area

Acadia National Park

Brigantine National Wildlife Refuge

Hybrid 2002 % of Modeled Extinction by Species 

Rank

Change in 

Vis (ddv) %_SO4 %_NO3 %_OC %_EC %_PMC
Julian 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

Dolly Sods

Hybrid 2002 % of Modeled Extinction by Species

Rank

Change in 

Vis (ddv) % SO4 % NO3 % OC % EC 
Julian 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 Range – Dry River

%_PMF

Lye Brook Wilderness Area

Acadia National Park

Brigantine National Wildlife Refuge

Hybrid 2002 % of Modeled Extinction by Species 

Rank

Change in 

Vis (ddv) %_SO4 %_NO3 %_OC %_EC %_PMC
Julian 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

Dolly Sods

Hybrid 2002 % of Modeled Extinction by Species

Rank

Change in 

Vis (ddv) % SO4 % NO3 % OC % EC 
Julian 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 Range – Dry River

%_PMF

Lye Brook Wilderness Area

Acadia National Park

Brigantine National Wildlife Refuge

Hybrid 2002 % of Modeled Extinction by Species 

Rank

Change in 

Vis (ddv) %_SO4 %_NO3 %_OC %_EC %_PMC
Julian 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

Dolly 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 Impacts (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 Impacts (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 Impacts (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 Impacts (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 0.053 
Julian 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 Range – Dry River

%_PMF

Lye Brook Wilderness Area

Acadia National Park

Brigantine National Wildlife Refuge

NWS 2002 % of Modeled Extinction by Species 

Rank

Change in 

Vis (ddv) %_SO4 %_NO3 %_OC %_EC %_PMC
Julian 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

Dolly Sods

NWS 2002 % of Modeled Extinction by Species

Rank

Change in 

Vis (ddv) % SO4 % NO3 % OC % EC 
Julian 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

Lye Brook Wilderness Area

Acadia National Park

Brigantine National Wildlife Refuge

Predicted using the NWS Meteorological Data Set

Eastman Business Park Restricted Case Visibility Impacts (delta deciview)

Presidential Range – Dry River
Julian 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

Dolly Sods
Julian 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 Range – Dry River

%_PMF

Lye Brook Wilderness Area

Acadia National Park

Brigantine National Wildlife Refuge

NWS 2002 % of Modeled Extinction by Species 

Rank

Change in 

Vis (ddv) %_SO4 %_NO3 %_OC %_EC %_PMC
Julian 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

Dolly Sods

NWS 2002 % of Modeled Extinction by Species

Rank

Change in 

Vis (ddv) % SO4 % NO3 % OC % EC 
Julian 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 Range – Dry River

%_PMF

Lye Brook Wilderness Area

Acadia National Park

Brigantine National Wildlife Refuge

NWS 2002 % of Modeled Extinction by Species 

Rank

Change in 

Vis (ddv) %_SO4 %_NO3 %_OC %_EC %_PMC
Julian 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

Dolly 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 Impacts (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 Impacts (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 Impacts (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 Impacts (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