Best Available Retrofit Technology Analysis

Consolidated Edison Company of New York, Inc. 

59th Street Station and Ravenswood Steam Plant

Prepared for:

Consolidated Edison Company of New York, Inc.

4 Irving Place

New York, NY 10003

Prepared by:

TRC Environmental Corporation

1200 Wall Street West, 2nd Floor

Lyndhurst, NJ 07071

September 2010
59th Street Station and Ravenswood Steam Plant BART Analysis

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TABLE OF CONTENTS

Section Page

EXECUTIVE SUMMARY.................................................................................iii

1.0 INTRODUCTION.............................................................................................................. 1

1.1 59th Street Station ............................................................................................................. 2

1.2 Ravenswood Steam Plant................................................................................................. 3

2.0 CONTROL TECHNOLOGY ANALYSIS ...................................................................... 5

2.1 Approach Used in BART Analysis .................................................................................. 5

2.1.1 Available Retrofit Control Technology........................................................................ 5

2.1.2 Costs of Compliance..................................................................................................... 5

2.1.3 Energy and Non-Air Quality Environmental Impacts of Compliance.......................... 7

2.1.4 Pollution Control Equipment in Use at the Source....................................................... 8

2.1.5 Remaining Useful Life of the Source ........................................................................... 8

2.1.6 Degree of Improvement in Visibility Which May Reasonably be Anticipated to Result 

from the Use of Such Technology............................................................................................ 8

2.1.7 BART Analysis............................................................................................................. 8

2.2 BART Analysis for NOx................................................................................................... 9

2.2.1 Available Retrofit Control Technology...................................................................... 10

2.2.2 Costs of Compliance................................................................................................... 14

2.2.3 Energy and Non-Air Quality Environmental Impacts of Compliance........................ 15

2.2.4 Pollution Control Equipment in Use at the Source..................................................... 16

2.2.5 Remaining Useful Life of the Source ......................................................................... 16

2.2.6 Degree of Visibility Improvement.............................................................................. 16

2.2.7 BART Proposal........................................................................................................... 17

2.3 BART Analysis for SO2 ................................................................................................. 17

2.3.1 BART Proposal........................................................................................................... 17

2.4 BART Analysis for PM-10............................................................................................. 17

2.4.1 Available Retrofit Control Technology...................................................................... 18

2.4.2 Pollution Control Equipment in Use at the Source..................................................... 20

2.4.3 Remaining Useful Life of the Source ......................................................................... 20

2.4.4 BART Proposal........................................................................................................... 20

3.0 VISIBILITY MODELING.............................................................................................. 21

3.1 Visibility Model ............................................................................................................. 21

3.2 Receptor Locations......................................................................................................... 21

3.3 Meteorological Databases .............................................................................................. 22

3.4 Visibility Index, Thresholds and CALPOST Processing ............................................... 26

3.5 Modeling Results............................................................................................................ 26
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LIST OF TABLES

Table 2-1 Summary of Cost-Effectiveness of Technologically Feasible NOx Control Options

Table 2-2 Summary of Cost-Effectiveness of Technologically Feasible SO2 Control Options

Table 3-1 Con Edison - 59th Street Pre-Controls - BART Class I CALPUFF Impacts

Table 3-2 Con Edison - 59th Street Post-Controls - BART Class I CALPUFF Impacts

Table 3-3 Con Edison - Ravenswood Pre-Controls - BART Class I CALPUFF Impacts

Table 3-4 Con Edison - Ravenswood Post-Controls - BART Class I CALPUFF Impacts

LIST OF FIGURES

Figure 3-1 Vermont Modeling Domain and Class I Areas

Figure 3-2 AECOM Modeling Domain and Class I Areas

LIST OF APPENDICES

Appendix A Emission Calculations

Appendix B Summary of BACT/LAER Determinations

Appendix C BART Cost Analyses

Appendix D NYSDEC Modeling Protocol

Appendix E Modeling Input and Output Files
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EXECUTIVE SUMMARY

In response to increased adverse visibility impacts at Class I “pristine” air quality areas due to 

existing major sources, the U.S. Environmental Protection Agency (EPA) promulgated the Best 

Available Retrofit Technology (BART) rules in 1999 and issued an updated Regional Haze Rule 

in 2005. For states with Class I areas, and for states that contain eligible stationary sources 

which may cause or contribute to regional haze issues in Class I areas contained in downwind 

states, EPA requires the implementation of measures to reduce emissions of these visibilityimpairing pollutants. While New York State contains no Class I areas, it has been identified as 

containing sources eligible for BART which contribute to the regional haze issue in Class I areas 

in other states. 

In order to be subject to BART, sources: (1) must have the potential to emit 250 tons per year or 

more of a visibility-impairing pollutant (VIP), namely nitrogen oxides, particulate matter less 

than 10 microns or sulfur dioxide; (2) were put in place between August 7, 1962 and August 7, 

1977; and (3) whose operations fall within one or more of 26 specifically listed categories. 

Fossil-fuel fired boilers with a maximum heat input of more than 250 million British thermal 

units per hour (MMBtu/hr) are one of the 26 listed BART source categories. As per notification 

by the New York State Department of Environmental Conservation (NYSDEC), Boilers #114 

and #115 located at the 59th Street Station and Boiler #2 at the Ravenswood Steam Plant are 

subject to BART. Sources subject to BART are required to submit their five-factor analysis of 

potential BART controls to the NYSDEC by October 1, 2010. 

A BART analysis was prepared for the three subject boilers based upon consideration of five 

statutory factors required by the Clean Air Act (CAA). These factors for available retrofit 

control technologies are: (1) the costs of compliance; (2) the energy and non-air quality 

environmental impacts of control options; (3) any pollution control equipment in use at the 

source (which affects the availability of options and their impacts); (4) the remaining useful life 

of the source; and (5) the degree of improvement in visibility which may reasonably be 

anticipated to result from the use of such technology. 

The CALPUFF model was used to evaluate visibility impacts of present emissions from the 59th

Street Station Boilers #114 and #115 and the Ravenswood Steam Plant Boiler #2 and BART 

control alternatives at the following seven Class I areas:

Brigantine

Lye Brook

Acadia

Presidential Range
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Great Gulf

Dolly Sods; and

Otter Creek.

The maximum and 98% percentile (or Highest 8th Highest, H8H) 24-hour visibility impact for 

the pre- and post-BART control source emissions for each Class I Area were determined. A 

summary of the visibility modeling results is provided in Section 3.0. 

A control technology analysis has been performed for the 59th Street Station Boiler #114 and 

Boiler #115 and the Ravenswood Steam Plant Boiler #2 in accordance with guidance presented 

in 40 CFR Part 51 and Appendix Y to 40 CFR Part 51 as well as guidance provided by 

NYSDEC. To identify retrofit control technology options for the subject equipment, a search of 

the U.S. EPA’s RACT/BACT/LAER Clearinghouse (RBLC) was performed for each VIP. For 

the purposes of determining dollar-per-ton cost-effectiveness of each technologically feasible 

control option, capital and O&M costs were based on order-of-magnitude vendor and consultant 

estimates. Costs analyses based on these estimates are provided in Appendix C.

Following is a summary of the conclusions of this analysis:

In accordance with NYSDEC guidance, the presumptive BART limit for oil fired units 

regardless of size is limiting the sulfur content of the oil fired to 1% by weight or less. 

The 59th Street Boilers #114 and #115 and the Ravenswood Steam Plant Boiler #2 have 

permit conditions which limit the maximum sulfur content of the fuel oil to 0.3% by 

weight. Since the units’ sulfur content limit is significantly below the presumptive BART 

limit for SO2, no additional SO2 controls were considered in this analysis.

Based upon guidance provided by NYSDEC, the threshold cost for determining whether a 

particular control technology is cost effective is $5,500/ton. The cost-effectiveness for all 

technically feasible NOx controls applied to the Ravenswood Steam Plant Boiler #2 are 

greater than $5,500/ton. Therefore, adding NOx controls to the Ravenswood Steam Plant 

Boiler #2 is cost-prohibitive. 

While the $/ton of NOx removed for water injection on the 59th Street Boilers #114 and 

#115 is slightly less than $5,500/ton, these values are based on the assumption that the 

units operate continuously (8,760 hours/year). Boilers #114 and #115 are steam-only 

boilers that do not produce electricity. These boilers follow Con Edison’s Steam System 

load changes, which results in their limited operation and significant unused capacity. 
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Further, the baseline NOx emissions were calculated using the maximum 24-hour NOx

emission rate since 2005. When calculating the $/ton of NOx removed based on actual 

historical operation, the cost effectiveness for all control technologies is greater than the 

$5,500/ton feasibility threshold. Therefore, additional NOx controls on these units are 

considered cost-prohibitive.

No add-on controls for PM appear to be demonstrated effective in practice for a utility 

boiler that burns fuel oil as the primary fuel. Therefore, the existing PM emission limits 

achieved through proper operation and maintenance of the boilers, as well as the use of 

low sulfur residual oil, are proposed as BART for the 59th Street Station Boilers #114 and 

#115 and the Ravenswood Steam Plant Boiler #2.
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1.0 INTRODUCTION

In Section 169A of the Clean Air Act (CAA), Congress declared as a national goal the prevention 

of any future, and remedying of any existing, visibility impairment in Federal Class I areas 

resulting from man-made pollutant emissions. For states with Class I areas, and for states that 

contain eligible stationary sources which may cause or contribute to regional haze issues in Class 

I areas contained in downwind states, the United States Environmental Protection Agency (EPA) 

requires the implementation of measures to reduce emissions of these visibility-impairing 

pollutants. While New York State contains no Class I areas, it has been identified as containing 

sources eligible for Best Available Retrofit Technology which contribute to the regional haze 

issue in Class I areas in other states. Accordingly, 6 NYCRR Part 249, "Best Available Retrofit 

Technology (BART)", was promulgated to ensure that proper advances will be made in fulfilling 

the goals of the CAA. The visibility-impairing pollutants (VIPs) have been identified as 

particulate matter less than or equal to 10 microns in diameter (PM-10), sulfur dioxide (SO2), and 

nitrogen oxides (NOx). 

To avoid confusion with other CAA requirements which also use the term "major stationary 

source" to refer to a somewhat different population of sources, the regional haze rule uses the 

term "BART-eligible source" to describe these sources. The BART-eligible sources are those 

sources which: (1) have the potential to emit 250 tons per year or more of a VIP; (2) were put in 

place between August 7, 1962 and August 7, 1977; and (3) whose operations fall within one or 

more of 26 specifically listed source categories. BART-eligible sources may be required to apply 

emissions control technology to reduce emissions of VIPs if such emissions are demonstrated to 

cause an adverse visibility impact at the nearest Class I areas. The major recommendations for 

BART visibility impact modeling and application of emissions controls are:

1. Identify BART-eligible sources (based on date of operation, potential emissions of VIPs 

and facility source category)

2. Identify which pollutants have greater than EPA-suggested de minimis emissions levels

3. Identify sources that are subject to BART

4. Identify baseline visibility impact of each BART source

5. Identify feasible controls and emission changes

6. Identify the change in visibility impact for each candidate BART control option

7. Compare the visibility improvement of BART control options to other statutory factors in 

the engineering analysis
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BART-eligible boilers at the 59th Street Station and the Ravenswood Steam Plant are each very 

large boilers classified in the fossil-fuel boilers of more than 250 million British thermal units per 

hour (MMBtu/hr) heat input BART category. As per notification by NYSDEC, units located at 

the 59th Street Station and Ravenswood Steam Plant that meet the date eligibility criteria (August 

7, 1962 – August 7, 1977) and that have the potential to emit greater than 250 tons per year of at 

least one of the VIPs are as follows.

 59th Street Station Boiler #114

 59th Street Station Boiler #115

 Ravenswood Steam Plant Boiler #2

Sources subject to BART are required to submit their five-factor analysis of potential BART 

controls to the NYSDEC by October 1, 2010. Control equipment or other emission reduction 

methods approved as BART must be installed and operating no later than January 1, 2014. If an 

applicable source chooses not to comply with the provisions of Part 249, it must permanently 

shut down operations by January 1, 2014. This report satisfies the requirement to submit a 

BART analysis by October 1, 2010.

1.1 59th Street Station

As stated above, the BART-eligible sources at the 59th Street Station are Boilers #114 and #115. 

Both boilers are Combustion Engineering fixed-tangential boilers installed in 1966. Each has a 

design maximum heat input capacity of 805 MMBtu/hr. Boilers #114 and #115 are steam-only 

boilers that do not produce electricity and follow steam load which results in limited operation 

and significant unused capacity. Both units burn low sulfur No. 6 fuel oil (0.3% sulfur by 

weight) as the primary fuel with natural gas being used for ignition. NOx emissions from each 

boiler are controlled with the use of off-stoichiometric firing. The boilers are subject to NOx

RACT and currently have a presumptive NOx RACT limit of 0.25 lb/MMBtu. Con Edison 

complies with NOx RACT under a system-averaging plan. Particulate matter emissions from 

Boiler #114 and Boiler #115 are limited to 0.1 lb/MMBtu (filterable PM only) in the facility’s 

Title V Operating Permit and demonstrate compliance by stack testing once per permit term.

The maximum annual potential emissions of VIPs from 59th Street Station Boiler #114 and 

Boiler #115 (per unit) are as follows:

 NOx – 1057.8 tons/year

 SO2 – 1107.1 tons/year
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 PM-10 – 387.8 tons/year (filterable + condensable PM-10)

Since potential emissions of NOx, SO2 and PM-10 from Boilers #114 and #115 each exceed 250 

tons/year, emissions of NOx, SO2 and PM-10 are addressed in this BART analysis.

Actual short-term emissions of filterable PM-10 were determined using the results of the most 

recent stack test performed in 2007 for the 59th Street Station boilers. Condensable PM 

emissions were calculated using AP-42 emission factors for fuel oil combustion. Actual short 

term emissions of SO2 were based upon AP-42 emission factors and the maximum sulfur content 

for fuel oil deliveries over the past five years. Actual annual emissions of NOx, SO2 and PM-10 

were based upon the average gallons of No. 6 fuel oil burned in the boilers over calendar years 

2007 through 2009. Potential and actual emission calculations are presented in detail in 

Appendix A.

1.2 Ravenswood Steam Plant

As stated above, the BART-eligible source at the Ravenswood Steam Plant is Boiler #2. Boiler 

#2 is a front wall fired boiler and was installed in 1962. This unit was manufactured by Babcock 

and Wilcox and has a design maximum heat input capacity of 424 MMBtu/hr. Boilers #2 is a

steam-only boiler that does not produce electricity and follows steam load which results in 

limited operation and significant unused capacity. This unit burns low sulfur No. 6 fuel oil 

(0.3% sulfur by weight) as the primary fuel with natural gas being used for ignition. Boiler #2 is 

subject to NOx RACT and has a presumptive NOx RACT limit of 0.25 lb/MMBtu. Con Edison 

complies with NOx RACT under a system-averaging plan. 

The maximum annual potential emissions of VIPs from Boiler #2 are as follows:

 NOx – 510.7 tons/year

 SO2 – 583.1 tons/year

 PM-10 – 204.3 tons/year

Since potential emissions of NOx and SO2 from Boiler #2 each exceed 250 tons/year, emissions 

of all VIPs (NOx, SO2 and PM-10) must be addressed in this BART analysis.

Actual short-term emissions of filterable PM-10 were determined using the results of the most 

recent stack test performed in 2008. Condensable PM emissions were calculated using AP-42 

emission factors for fuel oil combustion. Actual short term emissions of SO2 were based upon 
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AP-42 emission factors and the maximum sulfur content for fuel oil deliveries over the past five 

years. Actual annual emissions of NOx, SO2 and PM-10 were based upon the average gallons of 

No. 6 fuel oil burned in the boilers over calendar years 2007 through 2009. Potential and actual 

emission calculations are presented in detail in Appendix A.
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2.0 CONTROL TECHNOLOGY ANALYSIS

A control technology analysis has been performed for the 59th Street Station Boiler #114 and 

Boiler #115 and the Ravenswood Steam Plant Boiler #2 in accordance with guidance presented 

in 40 CFR Part 51 and Appendix Y to 40 CFR Part 51 as well as guidance provided by 

NYSDEC. Section 2.1 presents an overview of the five-factor assessment procedure used in this 

analysis. 

2.1 Approach Used in BART Analysis

The determination of BART must be based on an analysis of the best system of continuous 

emission control technology available and associated emission reductions achievable for each 

BART-eligible source that is subject to BART. 40 CFR Subpart 51.302 and guidance presented 

in Appendix Y to 40 CFR Part 51 states that the BART analysis must be based upon 

consideration of five statutory factors required by the Clean Air Act (CAA) to determine the 

appropriate level of control for BART. These factors for available retrofit control technologies 

are: (1) the costs of compliance; (2) the energy and non-air quality environmental impacts of 

control options; (3) any pollution control equipment in use at the source (which affects the 

availability of options and their impacts); (4) the remaining useful life of the source; and (5) the 

degree of improvement in visibility which may reasonably be anticipated to result from the use of 

such technology.

2.1.1 Available Retrofit Control Technology

To identify retrofit control technology options for the subject equipment, a search of the U.S. 

EPA’s RACT/BACT/LAER Clearinghouse (RBLC) has been performed. Individual searches 

have been performed for each subject pollutant (NOx, SO2 and PM-10) emitted from each 

emissions unit. Results of the RBLC search are summarized in Appendix B. 

2.1.2 Costs of Compliance

The cost of compliance factor involves calculation of the cost-effectiveness of each control 

technology option on a dollar per ton of pollution removed basis. Annual emissions with a 

control option are subtracted from baseline annual emissions to calculate tons of pollutants 

controlled per year. Annual costs, in dollars per year, are calculated by adding annual operation 

and maintenance costs to the annualized capital cost of an option (amortized over ten years). 
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Cost-effectiveness ($/ton) of an option is simply the equivalent annual cost ($/yr) divided by the 

annual pollution controlled (ton/yr). The facility can also calculate incremental costs when 

several control technology options with varying levels of emission control effectiveness are 

available.

Note that no economic analysis is required if either the most effective option is proposed or if 

there are no technically feasible control options. When required in the evaluation of technically 

feasible options, the cost-effectiveness evaluation is based on engineering estimates, vendor 

quotations, internal cost estimates and cost estimation guidelines presented in the January 2002 

U.S. EPA guidance document “OAQPS Control Cost Manual, Sixth Edition” (EPA 452/B-02-

001). 

The economic portion of the BART consists of a comparison of the annualized cost of each 

option to the annual emission reduction it can produce, represented as dollars per ton. The 

annualized cost of each option has two components: the annualized total capital investment and 

the annual operating and maintenance cost.

The Total Capital Investment (TCI) is the sum of the total direct costs (TDC) and total indirect 

costs. Direct costs are defined as the capital investment required to purchase equipment needed 

for the control system. Examples of direct costs include purchased equipment costs (PEC) and 

installation. Indirect costs include vendor engineering costs, costs for administration and 

supervisions, taxes and interest. 

The PEC for technically feasible control technologies are primarily based upon vendor 

quotations, Con Edison internal cost estimates or estimates from USEPA-published guidance 

documents. 

The capital recovery factor (CRF) is used to convert capital cost estimates into equivalent 

annualized costs. To annualize capital costs, an interest rate and project life must be estimated. 

When the CRF is multiplied by the capital investment, the product is the uniform end-of-year 

payment necessary to repay the investment in a defined amount of years. The CRF can be 

calculated based upon the following equation:

CRF = [i * (1+i)n] / [(1+i)n – 1]

Where: i = interest rate; and

n = number of years of the investment.
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An 8% nominal interest rate has been selected for this evaluation. The investment life, n, has 

been assumed equal to a ten-year payback period. These values are consistent with values 

presented in the OAQPS Control Cost Manual. Therefore, the TCI has been amortized over a 

ten-year period at an 8% interest rate. 

The Total Annual Operating Cost is defined as the expenses associated with the annual operation 

of the control equipment and is the sum of direct annual costs and indirect annual costs. Direct 

annual costs include operating and supervisory labor, maintenance labor and materials required 

to operate the control equipment. Examples of direct annual costs are maintenance labor 

associated with the up-keep of the control equipment, parts, costs for raw materials and catalyst 

replacement, and utility costs. Indirect annual costs include overhead, property taxes, insurance 

and administration (including environmental reporting) associated with the operation of the 

control equipment. 

Specific costing factors for feasible alternatives are identified in the appropriate pollutantspecific section. For the purposes of determining dollar-per-ton cost-effectiveness of the 

technologically feasible control equipment, emission reductions have been calculated based upon 

vendor estimates for an option compared to the base case emissions. Results of the cost analyses 

are included in Appendix C.

2.1.3 Energy and Non-Air Quality Environmental Impacts of Compliance

The energy requirements of the control technology are examined. An assessment is made on 

whether the use of that technology results in energy penalties or benefits. If such benefits or 

penalties exist, they are quantified in this step to the extent practicable. Because energy penalties 

or benefits can usually be quantified in terms of additional cost or income to the source, the 

energy impacts analysis can, in most cases, simply be factored into the cost impacts analysis. 

The primary focus of the environmental impact analysis is the reduction in ambient 

concentrations of the pollutant being emitted. Increases or decreases in emissions of other 

criteria or non-criteria pollutants may occur with some technologies, and should also be 

identified. Non-air impacts, such as solid waste disposal, increased water consumption/treatment 

and irreversible or irretrievable commitment of resources, should be identified/quantified if they 

are an issue for the project control options. 
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2.1.4 Pollution Control Equipment in Use at the Source

A source may already be using an emission control device to control emissions of VIPs. Use of 

an existing control device can be considered to represent the baseline emissions. Replacement of 

the existing control device with a more efficient control technology or improving the existing 

control technology can also be considered in the case-by-case BART analysis.

2.1.5 Remaining Useful Life of the Source

The BART source’s “remaining useful life” may be considered as one element of the overall cost 

analysis. The “remaining useful life” of a source, if it represents a relatively short time period, 

may affect the annualized costs of retrofit controls. The remaining useful life is the difference 

between: 

(1) the date that the proposed BART emission controls will be put in place (capital 

and other construction costs incurred before controls are put in place can be rolled 

into the first year, as suggested in U.S. EPA’s OAQPS Control Cost Manual); and

(2) the date the facility permanently stops operations. Where this affects the BART 

determination, this date should be assured by a federally- or State-enforceable 

restriction preventing further operation.

This BART analysis does not incorporate the remaining useful life of the BART-eligible sources 

into the cost analysis. However, the remaining useful life of the BART-eligible sources is 

discussed. 

2.1.6 Degree of Improvement in Visibility Which May Reasonably be Anticipated to Result 

from the Use of Such Technology

As appropriate, to complete the BART assessment, an impact analysis was conducted to 

determine the visibility improvement expected as a result of adding the various control 

technologies. Comparisons were made of the pre-control visibility impacts based on existing 

conditions to those anticipated to result from installing add-on control equipment.

2.1.7 BART Analysis

From the alternatives evaluated in the above-listed steps, the facility developed a chart displaying 

for each of the alternatives:
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(1) expected emission rate (tons per year, pounds per hour);

(2) emissions performance level (e.g., percent pollutant removed, emissions per unit 

product, lb/MMBtu, ppm);

(3) expected emissions reductions (tons per year);

(4) costs of compliance -- total annualized costs ($), cost effectiveness ($/ton), and 

incremental cost effectiveness ($/ton), and/or any other cost effectiveness 

measures (such as $/deciview1);

(5) energy impacts;

(6) non-air quality environmental impacts; and

(7) modeled visibility impacts.

Control options are evaluated on the following basis: 

(1) display the options evaluated; 

(2) identify the average and incremental costs of each option; 

(3) consider the energy and non-air quality environmental impacts of each option; 

(4) consider the remaining useful life; and

(5) consider the modeled visibility impacts. 

The facility provides justification for adopting the technology selected as the "best" level of 

control, including an explanation of the CAA factors that differentiated between or among BART 

control options. Even if the control technology is cost effective, there may be cases where the 

installation of controls would affect the viability of continued plant operations. 

2.2 BART Analysis for NOx

The formation of NOx is determined by the interaction of chemical and physical processes 

occurring within the furnace. There are two principal forms of NOx designated as “thermal” NOx

and “fuel” NOx. Thermal NOx formation is the result of oxidation of atmospheric nitrogen 

contained in the inlet gas in the high-temperature, post-flame region of the combustion zone. 

The major factors influencing thermal NOx formation are temperature, concentrations of nitrogen 

and oxygen in the inlet air and residence time within the combustion zone. Fuel NOx is formed 

by the oxidation of fuel-bound nitrogen. NOx formation can be controlled by adjusting the 

 

1

In the regional haze rule definition of deciview the EPA states: “A deciview is a haze index derived from 

calculated light extinction, such that uniform changes in haziness correspond to uniform incremental 

changes in perception across the entire range of conditions, from pristine to highly impaired” (40 CFR 

§51.301).
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combustion process and/or installing post-combustion controls. 

2.2.1 Available Retrofit Control Technology

A review of approximately 30 facilities with fuel oil-fired boilers with maximum heat inputs 

greater than 250 MMBtu/hr listed in the U.S. EPA’s RBLC (see Appendix B) lists NOx emission 

limits ranging from 0.06 to 0.730 lb/MMBtu. 59th Street Boilers #114 and #115 and 

Ravenswood Boiler #2 are subject to NYSDEC Part 227-2 (NOx RACT) as very large boilers. 

Very large boilers currently have a presumptive NOx RACT limit of 0.25 lb/MMBtu. Con 

Edison complies with NOx RACT through a system-wide averaging plan. The maximum 24-

hour NOx emission rate over the last five years of operation for the 59th Street Boilers #114 and 

#115 is 0.30 lb/MMBtu with an average 24-hour NOx emission rate of 0.209 lb/MMBtu. The 

maximum 24-hour NOx emission rate over the last five years of operation for Ravenswood Steam 

Plant Boiler #2 was 0.275 lb/MMBtu, with an average 24-hour NOx emission rate of 0.21 

lb/MMBtu. 

NOx emission controls listed in the RBLC for fuel oil- and/or natural gas-fired boilers with 

maximum heat inputs greater than 250 MMBtu/hr are:

 Low NOx Burners

 Ultra Low NOx Burners

 Water Injection

 Flue Gas Recirculation

 Selective Catalytic Reduction

 Selective Non-Catalytic Reduction

Although not listed in the U.S. EPA’s RBLC, the facility has identified the following additional 

NOx emission control devices for fuel oil-fired boilers with maximum heat inputs greater than 

250 MMBtu/hr:

 Overfire Air

Low and Ultra Low NOx Burners

Low NOx Burners (LNB) control NOx formation by carrying out the combustion in stages. These 

burners control the combustion staging at and within the burner rather than in the firebox. This 

control is achieved through design features which regulate the aerodynamic distribution and 
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mixing of fuel and air. By staging the combustion process, thermal NOx formation is reduced by 

lowering the peak flame temperature. In addition, fuel NOx formation is reduced by lowering the 

amount of oxygen in the initial combustion zone. Ultra Low NOx Burners (ULNB) control NOx

in the same manner as described above. 

The oil atomizers and burner swirlers on the 59th Street Boilers #114 and #115 have been 

modified to a low NOx design. No additional reduction is expected by the installation of LNBs 

on the 59th Street boilers. The oil atomizers and burner swirlers on Ravenswood Steam Plant

Boiler # 2 have also been modified to a low NOx design. However, the installation of LNB on 

the Ravenswood Steam Plant boiler is considered a technologically feasible retrofit option. 

Based on vendor information, a maximum of 15% NOx reduction is anticipated with the 

installation of LNB. ULNBs, however, are not compatible with heavy oil firing, therefore, they 

are not considered further in this analysis as a technically feasible option. 

Overfire Air

In the Overfire Air (OFA) process, the injection of air into the firing chamber is staged into two 

zones. The staging of the combustion air reduces NOx formation by two mechanisms. The 

staged combustion results in a cooler flame. In addition, the staged combustion also results in 

less oxygen reacting with fuel molecules. The degree of staging is limited by operational 

problems since the staged combustion results in incomplete combustion conditions and the 

staged combustion results in a longer flame.

The installation of OFA on the boilers is considered a technologically feasible option. OFA is 

estimated to provide approximately 20% NOx reduction for 59th Street Boilers #114 and #115 

and 25% NOx reduction below the current baseline NOx emissions for the Ravenswood Steam 

Plant Boiler #2.

Selective Non-Catalytic Reduction

Selective Non-Catalytic Reduction (SNCR) involves the reaction of ammonia radicals, produced 

from the reaction of injected NH3 with radicals present in the hot flue gas, to reduce nitric oxide 

(NO) to nitrogen (N2). The ammonia radicals can also be produced by the injection of urea. The 

reactions for SNCR are presented below:

For ammonia: 4NH3 + 4NO + O2 => 4N2 + 6H2O +heat

For urea: 2(NH2)2CO + 4NO + O2 => 4N2 + 4H2O + 2CO2 + heat
59th Street Station and Ravenswood Steam Plant

BART Analysis

12

The reactions presented above are predominant in the temperature range between 1,600 -

2,200 F. 

Based on the high temperature range required for the reaction to remove NOx emissions, an 

SNCR would need to be located inside the combustion chamber of the subject boilers. The 

installation of SNCR is feasible for the 59th Street boilers, but will be difficult to implement. 

There is limited access to suitable injector locations and very limited residence time for the 

chemical reactions to occur. The limited residence time and injector accessibility would limit the 

NOx reduction capabilities to approximately 20%. Similar to 59th Street, the installation of 

SNCR is considered a technologically feasible option for the Ravenswood Steam Plant Boiler #2, 

but will be difficult to implement due to the limited access to suitable injector locations and the

very short residence time. SNCR for Boiler #2 is estimated to provide approximately 20% NOx

reduction. 

Water Injection

Water injection involves injecting micronized water droplets into the NOx production zones of a 

gas burner flame. The use of water injection only treats thermal NOx. NOx reductions up to 10% 

have been demonstrated on heavy oil fired tangentially fired boilers, however there have been 

mixed results on heavy oil wall fired boilers. 

The use of water injection is considered a technically feasible control option for 59th Street 

Boilers #114 and #115. Water injection has not been demonstrated to provide reliable NOx

reduction for the Ravenswood Steam Plant Boiler #2.

Flue Gas Recirculation

Flue Gas Recirculation (FGR) controls NOx by recycling a portion of cold flue gas back into the 

primary combustion zone. The recycled air lowers NOx emissions by two mechanisms; (1) the 

recycled gas is made up of combustion products which act as inerts during combustion, thereby 

lowering combustion temperatures and (2) by lowering the oxygen content in the primary flame 

zone. The amount of recirculation is based on flame stability. Typically, 15% to 20% of the total 

flue gas is recycled. 

Two approaches are commonly used to inject the FGR into the combustion air. Forced FGR uses 

a separate fan (FGR fan) to inject the flue gas into the combustion air downstream of the FD fan. 

The second approach uses the suction of the FD fan to induce flue gas from the exhaust duct, 
59th Street Station and Ravenswood Steam Plant

BART Analysis

13

through the FD fan, and into the windbox (induced FGR). The installation of FGR on all of the 

boilers is considered a technologically feasible option. Induced FGR is lower in cost and 

provides the same percentage NOx reduction, therefore, only IFGR is considered further in this 

analysis. 

Based on vendor data, FGR is estimated to provide approximately 10% NOx reduction below the 

current baseline NOx emissions for the 59th Street Boilers #114 and #115 and 10% NOx reduction

for the Ravenswood Steam Plant Boiler #2.

 

Selective Catalytic Reduction

Selective Catalytic Reduction (SCR) involves the injection of diluted ammonia (NH3) into the 

exhaust gas stream upstream of a catalyst bed. On the catalyst surface, ammonia reacts with NOx

contained within the air to form molecular Nitrogen (N2) and water (H2O). 

4NH3 + 4NO + O2 => 4N2 + 6H2O

8NH3 + 6NO2 => 7N2 + 12H2O

It is important to have stable operations and uniform flue gas temperatures to achieve optimum 

NOx control. The catalyst exhibits optimum performance in a temperature range within +/- 50 F. 

Outside of this optimum range, the effectiveness of this catalyst is greatly reduced.

The temperature range for standard SCR operations is between 550 - 800 F. Since the SCR 

system is a post combustion control device, it would need to be located downstream from the 

combustion chamber of the boiler. 

The installation of SCR is considered a technologically feasible option for both Stations. Due to 

the configuration of the 59th Street Station units, implementing SCR on the boilers would present 

many challenges. The boilers would need to be reducted/reconfigured. These challenges result 

in extremely high costs. The Ravenswood Steam Plant has a very small footprint. The SCR 

module would need to be installed on the boiler building roof. The roof would need to be 

reinforced with steel to support the SCR module, resulting in a high capital cost. Based on 

discussions with a NOx emission control technology vendor, SCR is estimated to provide 

approximately 47% NOx reduction below the current baseline NOx emissions for the subject 

boilers. 
59th Street Station and Ravenswood Steam Plant

BART Analysis

14

2.2.2 Costs of Compliance

Based upon the assumptions presented in Section 2.1.2, cost of compliance analysis, on a $/ton 

basis, has been provided for technically feasible control equipment described in Section 2.2.1. A 

summary of the cost-effectiveness of each of the control devices evaluated is presented in Table 

2-1. A detailed cost analysis is presented in Appendix C.

Table 2-1 Summary of Cost-Effectiveness of Technologically Feasible NOx Control 

Options

BARTEligible 

Source

Control

Potential 

Annual NOx

Emission Rate 

(TPY)

Average 

Actual Annual 

NOx Emission 

Rate

2007-2009

(TPY)

NOx

Emission 

Reduction 

Performance 

(%)

Total 

Annualized 

Cost

CostEffectiveness 

based on

8,760 hrs/yr

($/ton)

CostEffectiveness 

based on 

expected 

annual 

operation

($/ton)

59th Street 

Boiler #114 

and #115

SCR 2116 817 47% $8,738,399 $8,788 $22,747

SNCR 20% $4,076,000 $9,633 $24,934

Water 

Injection

10% $712,490 $3,368 $8,717

OFA 20% $2,803,113 $6,625 $17,147

FGR 10% $2,601,209 $12,296 $31,825

Ravenswood 

Steam Plant

Boiler #2

SCR 511 83 47% $3,457,287 $14,403 $88,310

SNCR 20% $2,192,374 $21,464 $131,600

LNB 15% $1,897,018 $24,763 $151,828

OFA 25% $3,867,963 $30,295 $185,743

FGR 10% $623,974 $12,218 $74,910

Based upon guidance provided by NYSDEC, the threshold cost for determining whether a 

particular control technology is cost effective is $5,500/ton. The cost-effectiveness for all 

technically feasible NOx controls applied to the Ravenswood Steam Plant Boiler # 2 are greater 

than $5,500/ton. Therefore, adding NOx controls to the Ravenswood Steam Plant Boiler #2 is 

cost-prohibitive. 

While the $/ton of NOx removed for water injection on the 59th Street Boilers #114 and #115 is

less than $5,500/ton, these values are based on the assumption that the units operate continuously 

(8,760 hours/year). Boilers #114 and #115 are steam only boilers that do not produce electricity 

and follow steam load which results in limited operation and significant unused capacity. For 

practical purposes, Boilers #114 and #115 have an average annual capacity factor of less than 

60%. Further, the baseline NOx emissions were calculated using the maximum 24-hour NOx 
59th Street Station and Ravenswood Steam Plant

BART Analysis

15

emission rate since 2005. When calculating the $/ton of NOx removed based on actual operation, 

the cost effectiveness for all control technologies are greater than the $5,500/ton feasibility 

threshold. Therefore, additional controls on these units are considered cost-prohibitive.

2.2.3 Energy and Non-Air Quality Environmental Impacts of Compliance

Low NOx Burners

Energy and non-air quality environmental impacts of compliance for the use of LNB are 

minimal.

Overfire Air

OFA involves using energy to power a fan that can inject air into the firing chamber of the boiler. 

The boiler steam production has the potential to be reduced if there are any backpressure losses 

due to the OFA system. Also, the degree of OFA staging is limited by operational problems 

since the staged combustion results in incomplete combustion conditions and the staged 

combustion results in a longer flame thus burning more fuel.

Selective Non-Catalytic Reduction

There are additional costs associated with purchasing ammonia or urea. There would be an 

energy penalty that would be required to transport the ammonia/urea from the storage tank into 

the boiler. In addition, there are also water requirements to either dilute the concentrated 

ammonia or to mix with urea prior to injecting into the boiler. Transporting the reagent would 

also result in increased emissions due to truck traffic.

Flue Gas Recirculation

FGR involves using energy to power a fan that can re-inject a portion of cold flue gas back into 

the primary combustion zone. The boiler steam production has the potential to be reduced if 

there are any backpressure losses due to the FGR system.

Selective Catalytic Reduction

As described above for the SNCR system, there are also additional costs associated with 

purchasing ammonia or urea and additional water usage/costs. There would also be an energy 
59th Street Station and Ravenswood Steam Plant

BART Analysis

16

penalty that would be required to transport the ammonia/urea from the storage tank into the 

boiler and increased emissions from trucks transporting the reagent. The SCR catalyst needs to 

be replaced every few years of operation. Replacing the catalyst causes the facility to have 

increased solid waste. 

An undesirable side-effect of SCR is the potential formation of ammonium bisulfate (NH4HSO4) 

and ammonium sulfate ((NH4)2SO4), referred to as ammonium salts, which are corrosive and can 

stick to the heat recovery surfaces, duct work, or stack at low temperatures and results in 

additional PM/PM-10 formation if emitted. NH4HSO4 and (NH4)2SO4 are reaction products of 

SO3 and NH3. 

2.2.4 Pollution Control Equipment in Use at the Source

59th Street Boilers #114 and #115 and Ravenswood Steam Plant Boiler #2 are operated with good 

combustion/operating practices. In addition, the oil atomizers and burner swirlers on the 59th

Street Boilers #114 and #115 have been modified to a low NOx design. The facilities employ a 

continuous emission monitoring system (CEMS) that measures NOx, O2 and CO2 to ensure that 

the boilers comply with Con Edison’s system-wide NOx RACT emission limit. Use of the 

CEMS system allows for the boiler operator to optimize combustion and minimize emissions of 

NOx and other pollutants.

2.2.5 Remaining Useful Life of the Source

The 59th Street Station Boilers #114 and #115 were installed in 1966. The Ravenswood Steam 

Plant Boiler #2 was installed in 1962. It is assumed that the normal useful life of a utility boiler 

is between 30 and 60 years. 

2.2.6 Degree of Visibility Improvement

An impact analysis was conducted to assess the visibility improvement of the various NOx

controls. See Section 3 for detailed visibility modeling results. In summary, for the 59th Street 

boilers, the only NOx control which resulted in a cost-effectiveness less than $5,500/ton of NOx

removed (potential emissions basis) was water injection (10% NOx control). Based on a 

conservative 20% NOx reduction, the degree of visibility improvement ranged from 1.8% to 

2.6% (using the 98th percentile values). This corresponds to a negligible visibility improvement 

from existing conditions. 
59th Street Station and Ravenswood Steam Plant

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17

2.2.7 Proposal for NOx BART Compliance

Based on actual operation of the boilers, the use of additional NOx controls is considered cost 

prohibitive. In addition to cost, there are additional energy requirements and non-air quality 

environmental impacts associated with each of the NOx emission control technologies under 

consideration. Further, the degree of visibility improvement as a result of employing these 

controls is negligible (< 3%). Therefore, no additional NOx emission control technology is 

proposed. The boilers will continue to use good combustion/operating practices and low NOx oil

atomizers and burner swirlers to comply with BART for NOx. 

2.3 BART Analysis for SO2

SO2 emissions are formed from oxidation of sulfur in the fuel. Strategies for the control of SO2

emissions can be divided into pre- and post-combustion categories. Pre-combustion controls 

entail the use of low-sulfur fuels. Post-combustion controls comprise various wet and dry flue 

gas desulfurization processes.

In accordance with NYSDEC guidance, the presumptive BART limit for oil fired units regardless 

of size is limiting the sulfur content of the oil fired to 1% by weight or less. The 59th Street 

Boilers #114 and #115 and the Ravenswood Steam Plant Boiler #2 have permit conditions which 

limit the maximum sulfur content of the fuel oil to 0.3% by weight. Since the units sulfur 

content limit is significantly below the presumptive BART limit for SO2, no additional SO2

controls were considered in this analysis.

2.3.1 Proposal for SO2 BART Compliance

In accordance with NYSDEC guidance, the presumptive BART limit for oil fired units regardless 

of size is limiting the sulfur content of the oil fired to 1% by weight or less. Therefore, the 

existing maximum fuel oil sulfur content limit of 0.3% by weight is proposed as BART for the 

59th Street Station Boilers #114 and #115 and the Ravenswood Steam Plant Boiler #2.

2.4 BART Analysis for PM-10

PM-10 emissions may be categorized as either filterable or condensable. Filterable emissions are 

generally considered to be the particles that are trapped by the glass fiber filter in the front half of 

a Reference Method 5 or Method 17 sampling train. Vapors and particles less than 0.3 microns 

pass through the filter. Condensable particulate matter is material that is emitted in the vapor 

state which later condenses to form homogeneous and/or heterogeneous aerosol particles. The 
59th Street Station and Ravenswood Steam Plant

BART Analysis

18

condensable particulate emitted from boilers fueled on coal or oil is primarily inorganic in nature. 

Filterable particulate matter emissions depend predominantly on the grade of fuel fired. 

Combustion of lighter distillate oils results in significantly lower PM formation than does 

combustion of heavier residual oils. Among residual oils, firing of No. 4 or No. 5 oil usually 

produces less PM than does the firing of heavier No. 6 oil. 

In general, filterable PM emissions depend on the completeness of combustion as well as on the 

oil ash content. The PM emitted by distillate oil-fired boilers primarily comprises carbonaceous 

particles resulting from incomplete combustion of oil and is not correlated to the ash or sulfur 

content of the oil. However, PM emissions from residual oil burning are related to the oil sulfur 

content. This is because low sulfur No. 6 oil, either from naturally low-sulfur crude oil or 

desulfurized by one of several processes, exhibits substantially lower viscosity and reduced 

asphaltene, ash, and sulfur contents, which results in better atomization and more complete 

combustion.

Boiler load can also affect filterable particulate emissions in units firing No. 6 oil. At low load 

(50 percent of maximum rating) conditions, particulate emissions from utility boilers may be 

lowered by 30 to 40 percent and by as much as 60 percent from small industrial and commercial 

units. However, no significant particulate emission reductions have been noted at low loads from 

boilers firing any of the lighter grades. At very low load conditions (approximately 30 percent of 

maximum rating), proper combustion conditions may be difficult to maintain and particulate 

emissions may increase significantly.

2.4.1 Available Retrofit Control Technology

A review of 19 facilities with fuel oil-fired boilers having maximum heat inputs greater than 250 

MMBtu/hr listed in the U.S. EPA’s RBLC (see Appendix B) lists PM-10 emission limits ranging 

from 0.003 to 0.210 lb/MMBtu. The 59th Street Boilers #114 and #115 and Ravenswood Steam 

Plant Boiler #2 each employ good combustion practices and use of low sulfur residual oil to 

minimize PM-10 emissions. Each facility has a Title V permit which limits PM emissions to 0.10 

lb/MMBtu. Stack testing performed in 2007 for the 59th Street Boilers shows that PM emissions 

are approximately half (0.056 lb/MMBtu) of the permitted emission limit of 0.10 lb/MMBtu. In 

2008 stack testing for PM was performed on the Ravenswood Steam Plant Boiler #2. Stack test 

results indicate that actual PM emissions are significantly less (0.025 lb/MMBtu) than the 

permitted emission limit of 0.10 lb/MMBtu.
59th Street Station and Ravenswood Steam Plant

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19

PM-10 emission controls listed in the RBLC for fuel oil-fired boilers with maximum heat inputs 

greater than 250 MMBtu/hr are:

 Electrostatic Precipitator

 Fabric Filter/Baghouse

 Cyclone

Electrostatic Precipitator

An Electrostatic Precipitator (ESP) is a particulate control device that uses electrical forces to 

move particles entrained within an exhaust stream onto collection surfaces. The entrained 

particles are given an electrical charge when they pass through a corona, a region where gaseous 

ions flow. Electrodes in the center of the flow lane are maintained at high voltage and generate 

the electrical field that forces the particles to the collector walls. In dry ESPs, the collectors are 

knocked, or “rapped”, by various mechanical means to dislodge the particulate, which slides 

downward into a hopper where they are collected. The hopper is evacuated periodically, as it 

becomes full. Dust is removed through a valve into a dust-handling system, such as a pneumatic 

conveyor, and is then disposed of in an appropriate manner.

The boilers listed in the RBLC as having ESP systems all are designed and operate to primarily 

burn coal, waste fuels and/or wood waste. Since this control technology does not appear to be 

demonstrated in practice for a utility boiler that burns fuel oil as the primary fuel, it is not 

considered any further in this analysis.

Fabric Filter/Baghouse

In a fabric filter, flue gas is passed through a tightly woven or felted fabric, causing PM-10 in the 

flue gas to be collected on the fabric by sieving and other mechanisms. Fabric filters may be in 

the form of sheets, cartridges, or bags, with a number of the individual fabric filter units housed 

together in a group. Bags are the most common type of fabric filter. The dust cake that forms on 

the filter from the collected PM can significantly increase collection efficiency. Fabric filters are 

frequently referred to as baghouses because the fabric is usually configured in cylindrical bags. 

Bags may be 6 to 9 m (20 to 30 ft) long and 13 to 31 centimeters (cm) (5 to 12 inches) in 

diameter. Groups of bags are placed in isolable compartments to allow cleaning of the bags or 

replacement of some of the bags without shutting down the entire fabric filter.
59th Street Station and Ravenswood Steam Plant

BART Analysis

20

The boilers listed in the RBLC as having fabric filters or baghouse systems all are designed and 

operate to primarily burn coal, waste fuels and/or wood waste. Since this control technology 

does not appear to be demonstrated in practice for a utility boiler that burns fuel oil as the 

primary fuel, it is not considered further in this analysis.

Cyclone

Cyclones use inertia to remove particles from the gas stream. The cyclone imparts centrifugal 

force on the gas stream, usually within a conical shaped chamber. Cyclones operate by creating a 

double vortex inside the cyclone body. The incoming gas is forced into circular motion down the 

cyclone near the inner surface of the cyclone tube. At the bottom of the cyclone, the gas turns 

and spirals up through the center of the tube and out of the top of the cyclone. The use of 

cyclones to control PM-10 emissions from utility boilers that primarily burn fuel oil and/or

natural gas is not specifically listed in the records of the RBLC.

2.4.2 Pollution Control Equipment in Use at the Source

59th Street Boilers #114 and #115 and Ravenswood Steam Plant Boiler #2 each employ good 

combustion practices and use of low sulfur residual oil to minimize PM-10 emissions. 

2.4.3 Remaining Useful Life of the Source

The 59th Street Station Boilers #114 and #115 were installed in 1966. The Ravenswood Steam 

Plant Boiler #2 was installed in 1962. It is assumed that the normal useful life of a utility boiler 

is between 30 and 60 years. 

2.4.4 Proposal for PM-10 BART Compliance

The add on control technologies identified above do not appear to be demonstrated in practice for 

a utility boiler that burns fuel oil as the primary fuel. Therefore, the existing PM emission limits 

achieved through proper operation and maintenance of the boiler as well as the use of low sulfur 

residual oil are proposed as BART for the 59th Street Station Boilers #114 and #115 and the 

Ravenswood Steam Plant Boiler #2.
59th Street Station and Ravenswood Steam Plant

BART Analysis

21

3.0 VISIBILITY MODELING

Visibility modeling was performed to assess the impacts from three Con Edison sources - the 

59th Street Station Boilers 114 and 115, and Boiler #2 at the Ravenswood Steam Plant – at seven 

Class I areas. These seven Class I areas are: Brigantine, Lye Brook, Acadia, Presidential Range, 

Great Gulf, Dolly Sods and Otter Creek.

The “default recommendations” of the NYSDEC Guidance And Protocol For Visibility Modeling 

Of Bart Eligible Sources, Final: February 25, 2010 were followed. 

3.1 Visibility Model 

As recommended in the NYSDEC protocol, this analysis was performed with the regulatory 

version 5.8 of the CALPUFF modeling system. The model was used to assess atmospheric 

dispersion and in-transit chemistry to estimate visibility impairment from the Con Edison BART 

sources in New York. The model was run twice: once for pre-control and once for post-control. 

This allows the net improvement of the BART controls to be determined, by comparing the preand post-control scenarios.

The EPA/FLM “default” model options were used within this analysis for the various parameters

in the CALPUFF model runs.

Due to the large number of grid cells in the AECOM domain2, CALPUFF version 5.8 was 

recompiled with the Lahey-Fujitsu Fortran compiler version 7.1 to accept the parameters in the 

CALMET dataset. This executable is included with the modeling files.

3.2 Receptor Locations

As directed by the protocol, the standard receptor locations for each of the seven Class I areas 

were downloaded from the National Park Service (NPS) Air Resources Division website. 

(http://www.nature.nps.gov/air/maps/Receptors/index.cfm).

The receptors are created by the National Park Service, and are placed approximately one 

kilometer apart. Depending on the size of the Class I area, the receptors are then extracted to 

 

2 The AECOM dataset incorporates the MANE-VU MM5 wind field data as well as NWS observations. 

This dataset was more refined in all 3 dimensions, being based upon a 4 kilometer grid cell spacing, with 

11 vertical layers. It included 263 grid cells in the X direction, and 325 grid cells in the Y direction. 
59th Street Station and Ravenswood Steam Plant

BART Analysis

22

every second, every third or every fourth receptor in an effort to keep the number of receptors 

between 100 and 1000 per area.

The receptor locations are received in Latitude/Longitude coordinate format from the National 

Park Service. To be used within the model, they must be converted to a Lambert Conical 

Conformal (LCC) coordinate system appropriate to each of the two pre-processed CALMET 

meteorological databases provided by NYSDEC. 

It should be noted that, even though the protocol suggests its use, the NPS conversion program is 

inappropriate to use in this case without additional conversions. When converting from the 

default Lat/Lon coordinates to a LCC coordinate system, the NPS program forces the output into 

the NWS84 datum, also known as the NWS 6370KM Radius, Sphere datum. 

In contrast, the Vermont CALMET dataset is in WGS-G datum, or the WGS-84 GRS 80 

Spheroid, Global coverage (WGS84) datum. And the AECOM CALMET dataset is in NAS-C 

datum, or the NORTH AMERICAN 1927 Clarke 1866 Spheroid, MEAN FOR CONUS 

(NAD27) datum.

If the receptor locations are converted in the NPS program only and placed within the two 

CALMET coordinate systems, an approximate five (5) kilometer east-west offset, or error, in the 

receptor locations will occur. The receptor locations within the Vermont CALPUFF/CALMET 

analysis, as provided on hard drive by the NYSDEC, contain this discrepancy.

This issue was discussed with Margaret Valis of the NYSDEC - Air Resource Division by email. 

She directed TRC to make certain that the receptor LCC datum matches the datum of the 

CALMET datasets to ensure that the correct receptor coordinates are used in the analysis.

Therefore the conversion process was accomplished by using the “CALPUFF Coords” 

conversion program. This program allows the user to select the LCC output datum, such that it 

matches the datum used in the other stages of CALPUFF/CALMET.

3.3 Meteorological Databases

As suggested by the protocol, two pre-processed CALMET datasets were received on a hard 

drive from the NYSDEC for this study. This was the Vermont CALMET dataset, and the 

AECOM CALMET dataset, both from the 2002 calendar year. 
59th Street Station and Ravenswood Steam Plant

BART Analysis

23

The VT DEC CALMET dataset utilized National Weather Service meteorological observations 

only (i.e. radiosonde measurements for the upper atmospheric representation, Automated Surface 

Observing Station (ASOS) for the surface, and precipitation observers’ measurements). This 

dataset is based upon thirty six (36) kilometer grid cells spacing, with 74 grid cells in the X 

direction, and 60 grid cells in the Y direction, and eight (8) vertical layers. See Figure 3-1.

The second CALMET dataset, provided by NYSDEC, was the AECOM dataset. This data 

incorporates the MANE-VU MM5 wind field data, as well as NWS observations discussed in the 

previous paragraph. This dataset was more refined in all 3 dimensions, being based upon a 4 

kilometer grid cell spacing, with 11 vertical layers. It included 263 grid cells in the X direction, 

and 325 grid cells in the Y direction. However, it does cover a smaller geographic extant. See 

Figure 3-2.
59th Street Station and Ravenswood Steam Plant BART Analysis

24

Figure 3-1 – Vermont Modeling Domain and Class I Areas
59th Street Station and Ravenswood Steam Plant BART Analysis

25

Figure 3-2 – AECOM Modeling Domain and Class I Areas
59th Street Station and Ravenswood Steam Plant BART Analysis

26

3.4 Visibility Index, Thresholds and CALPOST Processing

As recommended in the protocol, the CALPUFF model runs were post processed to obtain the 

following results:

1) The maximum and 98% percentile (or Highest 8th Highest, H8H) 24 hour visibility 

impact for the pre and post BART control source emissions for each Class I Area, from 

both the 59th Street and Ravenswood facilities. 

2) The impacts calculated in #1 also provide the individual contribution of Sulfates (SO4),

Nitrates (NO3) and particulate emissions (PMC + PMF), on a percentile basis.

3) The number of days of visibility impacts, at each Class I Area, which exceed a deciview 

value of 0.1, 0.5 and 1.0 for the pre and post BART control source from both the 59th

Street and Ravenswood facilities. 

In addition, these visibility impacts were calculated relative to the 20% best days natural 

background levels, at each of the seven Class I Areas, as defined by the Federal Land Managers 

within the draft 2008 FLAG revised document. 

Also in accordance with the 2008 FLAG revised document, the “new” IMPROVE equation used 

for extinction coefficient calculations was used. This was accomplished by using CALPOST 

version 6.221, which contains the new equations. The default Method 8 “FLAG 2008” options 

were selected within the post processing.

As with the CALPUFF executable, the CALPOST executable had to be recompiled with the LF 

Fortran compiler, to allow for the large domain used within the AECOM CALMET dataset. This 

executable is included with the modeling files.

3.5 Modeling Results

The modeling results are presented in the following tables:
59th Street Station and Ravenswood A House BART Proposal

27

Table 3 - 1 ConEdison - 59th Street Pre-Controls - BART Class I CALPUFF Impacts
59th Street Station and Ravenswood A House BART Proposal

28

Table 3 - 2 ConEdison - 59th Street Post Controls - BART Class I CALPUFF Impacts

Note: Post control case corresponds to a 20% NOx reduction.
59th Street Station and Ravenswood A House BART Proposal

29

Table 3 - 3 ConEdison – Ravenswood Pre-Controls - BART Class I CALPUFF Impacts
59th Street Station and Ravenswood A House BART Proposal

30

Table 3 - 4 ConEdison – Ravenswood Post Controls - BART Class I CALPUFF Impacts

Note: Post control case corresponds to a 30% NOx reduction.
59th Street Station and Ravenswood Steam Plant BART Analysis

31
APPENDIX A

EMISSION CALCULATIONS



APPENDIX B

SUMMARY OF BACT/LAER DETERMINATIONS


APPENDIX C

BART COST ANALYSES




APPENDIX D

NYSDEC MODELING PROTOCOL
1 Guidelines for BART determination under the Regional Haze Rule, Appendix Y to Part

51; see final Preamble and BART Guidelines at: http://www.epa.gov/air/visibility/actions.html 

2

http://www.nescaum.org/topics/regional-haze/regional-haze-documents

NYSDEC GUIDANCE AND PROTOCOL FOR 

VISIBILITY MODELING OF BART ELIGIBLE SOURCES

Final: February 25, 2010

I. Background. The federal Regional Haze Rule’s provisions for the determination of Best

Available Retrofit Technology (BART) was finalized on June 15, 20051 and contains a

requirement to assess the net visibility improvement for sources subject to BART, as one of five

statutory factors in the determination of best control alternative for subject sources. The EPA

BART Guidelines provide states considerable flexibility in determining both the approach to be

taken in the visibility assessment as well as in the associated determinations leading to the best

option for choosing BART, but it nonetheless contains some general recommendations which

have been incorporated in our approach. In addition to EPA’s guidance, the NESCAUM

organization and the MANE-VU Regional Planning Organization have provided a number of

documents and have performed a first level, yet comprehensive visibility assessment of the

impact of BART eligible sources to regional haze at a set of Class I areas in the Northeast and

mid-Atlantic states2

. Specifically, certain aspects of the approach used in the document

“Contribution to Regional Haze in the Northeast and Mid-Atlantic United States”, dated August

31, 2006, are used as the basis for the guidance provided herein. 

EPA’s BART Guidelines recommend the development of a modeling protocol and

provides some general items to be addressed in the visibility analysis approach. This protocol

identifies a set of NYSDEC “default” recommendations to be used specifically for the modeling

approach for BART sources in New York in order to calculate the net improvements in visibility

at a set of Class I areas. These recommendations are based, in part, on the EPA guidance and

NESCAUM documents noted previously, but have been further refined and updated to

incorporated more recent EPA guidance on application of the CALPUFF/CALMET modeling

package, as well as based on discussions with the involved agencies, including EPA Region 2,

Vermont DEC, and the Federal Land Managers(FLMs) for Class I areas. 

The list of BART eligible sources in New York were previously identified during the

NESCAUM modeling exercise and subsequently finalized with the involved companies per the

effected units. Originally, this protocol was developed for the non-EGU units from the list under

the assumption that the CAIR regulations would serve as a sufficient surrogate for BART

determined control measures. However, due to current uncertainty in the status of the CAIR

rule, it has been determined that all eligible sources will have to undergo a BART review. In

addition, while the NESCAUM regional study document “Five Factor Analysis of BART Eligible

Sources-Survey of Options for Conducting BART Determinations”, dated June 1, 2007 (at

NESCAUM page in footnote 2) tentatively identified all of the eligible units as subject to BART
3 Guidelines on Air Quality Models, Revised December 9, 2005, Appendix W of 40 CFR,

Part 51.

4

http://www2.nature.nps.gov/air/permits/flag/index.cfm

5

http://www.epa.gov/ttn/scram/dispersion_prefrec.htm#calpuff

-2-

based on the assumption that these have a significant contribution to or “cause” regional haze,

the current protocol follows the BART rule in allowing “exemption modeling” for sources which

could demonstrate visibility impacts below a relatively low threshold of 0.1deciviews per

NYSDEC’s BART rule. All involved sources have already been notified that they must conduct

the five factor BART analysis and present that information for NYSDEC review if the specific

units are not exempted from the rule. In addition, concurrent with finalizing this protocol,

facilities containing BART eligible units have been ask to provide updated emission rate and

stack parameter information. 

To assist in the modeling determination of the net improvement in visibility with the

application of BART “alternatives” and in NYSDEC’s incorporation of this factor in the overall

BART determination, the following modeling approach and methodologies are recommended for

use by BART eligible sources.

II. Visibility Modeling Methodology. This section identifies the model and its input and output

requirements which NYSDEC has deemed acceptable, without a case specific modeling

protocol, for the assessment of visibility impacts from sources subject to BART. These

recommendations allow for consistent and equitable application of the visibility modeling using

a “default” set of conditions which have been determined consistent with both EPA BART

guidance and acceptable procedures. If a source chooses to deviate significantly from these

procedures, then a source specific protocol must be submitted for NYSDEC review. In the latter

case, adherence to recommendations in EPA’s Modeling Guidelines3

 and subsequent EPA

clarification memos on CALPUFF and CALMET, as well as in the IWAQM report (proposed

revised version, May 27, 2009) recommended in the BART Guidelines should be followed. 

These should also conform with recommendations from the the FLM’s Air Quality Related

Values Workgroup(FLAG) in their revised June 27, 2008 document4

. The following set of

specific recommendations are made:

1) Visibility Model. Although the BART Guidelines and the NESCAUM report do not

recommend a specific model for use in visibility assessment, they nonetheless note that the

CALPUFF modeling system (with associated meteorological data and post processors) are an

appropriate tool for such an assessment. Furthermore, EPA’s Modeling Guidelines recommend

the CALPUFF model for long range transport assessments, such as for impacts at Class I areas. 

In addition, a large number of BART and similar Class I assessments have relied on the

CALPUFF modeling results for decision making. Thus, the CALPUFF model (version 5.8,

level 070623)5

 is recommended as the “default” model to be used in these visibility assessments, 

with the EPA/FLM “default” options set for the various parameters. The use of these default
-3-

settings will essentially simulate the conditions used in the NESCAUM assessments, with

corrections for model code errors found in the previous versions. In addition, the

CALMET/CALPUFF application for the NESCAUM regional haze study was based on an

evaluation of certain of the model input parameters against observations, thus giving further

weight to the final approach chosen. A copy of an example CALPUFF input file has been

obtained from Vermont DEC and will be provided to the sources.

In instances where a source would like to apply a model other than CALPUFF, a detailed

modeling protocol should be submitted for DEC and EPA review prior to undertaking the BART

visibility analysis. It should be recognized that in these cases, it will be necessary to 

demonstrate the appropriateness of the model for the specific application and to explain any

deviations from current EPA guidance on model input and output processors. For example, the

meteorological data input requirements as well as any post processing of visibility impacts must

conform to the general recommendations in this document. 

2) Receptors locations. The set of seven eligible non-EGU sources in New York which could

be potentially subject to BART and which might have to perform a “net” visibility analysis are

located in the upstate region of New York and in the generally upwind direction of the Class I

areas in Vermont and New Hampshire. The BART guidelines notes that the nearest Class I area

and any others in close proximity should be included in the analysis. For these non-EGU

sources, the NESCAUM screening analysis indicated that all of the maximum visibility impacts

occurred consistently at the Lye Brook area. Thus, it might be sufficient to model only the Lye

Brook area since the White Mountain Class I area in New Hampshire is in the general downwind

direction and at considerably further distance from these sources than the Lye Brook area. 

However, since a few of the EGU sources were found to maximize at the New Hampshire

receptors, and since it will be informative to determine the level of improvement in visibility due

to BART alternatives, the receptors in New Hampshire Class I areas as well as in all other areas

noted for EGUs should be included in the analysis. 

For the EGU sources, the NESCAUM modeling results indicated that the Class I area

most impacted was the Brigantine Wilderness in New Jersey. In addition, two sources had

maxima at the Acadia National Park in Maine, while one source in western New York

maximized at the Dolly Sods Wilderness in West Virginia. Thus, for completeness and to

provide potential visibility impact reductions at other than maximum impacted areas, all

receptors in these and adjacent Class I areas defined below should be included in the modeling of

both EGU and non-EGU units. 

The BART guidelines indicate that receptors of sufficient density should be located at the

nearest Class I area. The example Vermont DEC CALPUFF application file noted above

contains a set of 103 receptors at Lye Brook which were developed with input from the National

Park Service(NPS)/FLM. A set of receptors recommended for all of the Class I areas are
6

 See http://www.nature.nps.gov/air/maps/Receptors/index.cfm

7 Appendix D: Development of Parallel CALPUFF Dispersion Modeling Platforms for

Sulfate Source Attribution Studies in the Northeast U.S. August 31, 2006.

http://www.nescaum.org/documents/contributions-to-regional-haze-in-the-northeast-and-mid-atlantic--united-states/ 

-4-

available from NPS site6 and should be used for the following Class I areas: Lye Brook, Acadia,

Brigantine, Presidential Range, Great Gulf, Dolly Sods and Otter Creek. These receptors grids

have been determine provide appropriate coverage of the individual Class I areas. A conversion

program is also available at the NPS webpage in case the input to CALPUFF is desired in a

format other than latitude/longitude.

3) Meteorological Data. Of major significance for the CALPUFF application are the set of

surface and upper level meteorological data which are input through the CALMET processor to

properly determine transport and dispersion conditions. The processing of such data is both

resource intensive and technically challenging. The CALMET processed data used for the

NESCAUM regional haze/sulfate source attribution analysis for BART eligible sources were

developed using data for the year 2002 in two different “platforms”; one using NWS

observations only by Vermont DEC and another using prognostic MM5 generated wind fields by

University of Maryland, with certain non-wind surface observations for use by Maryland

Department of Environment and with assistance from ERM consultants. Details of the

meteorological data processing and application are provided in Appendix D7

 of the August 31,

2006 NESCAUM report. Both of the meteorological data sets used in the NESCAUM analysis

were generated on a 12km grid and were further “refined” through a process which evaluated the

set of CALMET variable settings against observations. For example, for the Vermont DEC

application, comparisons were made between CALMET generated wind fields against

observations at mid level of the boundary layer and radiosonde data. The particular settings

which were deemed representative and were used in the final assessments are discussed and

presented in Appendix D. 

The two sets of CALMET generated data for the year 2002 did show differences in

certain fields. This is not unexpected nor contrary to general findings with CALMET

applications, given the differences in the methods of data simulation and assimilation. However,

there was no determination in the NESCAUM assessment as to which data base was preferred

for CALPUFF applications, especially for a specific set of conditions such as New York BART

sources and Class I areas of varying distances. Our original recommended approach was to use

both data sets for the BART visibility assessments which would provide an “enveloped”

analysis for the differences in wind fields associated with the two data sets. 

Since our original recommendations at the end of 2007, EPA has undertaken a more

rigorous review of the CALPUFF/CALMET modeling approach for BART modeling. Based in

part on this review, EPA set out recommendations specific to the grid resolution and the
8

 “Model Clearinghouse review of CALPUFF Modeling Protocol for BART”. May 15,

2009 Memo from Tyler Fox to Kevin Golden of EPA Region 8 and May 27, 2009 draft revisions

to IWAQM Phase 2 report. 

9 “Clarification on EPA-FLM Recommended Settings for CALMET”. August 31, 2009

memo from Tyler Fox to Regional EPA Modeling Contacts. 

10Comments on EPA’s proposed revisions to IWAQM Phase 2 report. Submitted by Dan

Riley of Vermont DEC (available upon request).

-5-

CALMET use of MM5 generated fields in a proposed revision to the IWAQM Phase 2 report8

. 

In essence, the recommendation on grid resolution indicate that refinements to much lower grid

resolution than used in the NESCAUM modeling (12km) or below a 4km spacing are not

supported at this time. On the other hand, EPA noted that the use of CALMET with a “hybrid”

mix of MM5 and NWS observation fields was the preferred approach. Subsequently, however,

EPA also indicated that certain of its previous recommendations needed further review based on

initial CALMET performance evaluations which indicated performance deterioration under

certain recommended settings9

. The latter memorandum did identify a set of “default” settings

for CALMET which are preferred by EPA and the FLMs. 

 Neither of the previously generated NESCAUM meteorological data bases for 2002

follow the specific recommendation of using a “hybrid” data base found in the latest EPA

guidance. However, the guidance does indicate that an alternative approach to the “blending” of

prognostic and observational data can be used if it has equal technical merit. In comments

submitted by the State of Vermont on EPA’s proposed revisions to the IWAQM report 10

(supported by NESACUM states) background analyses on the use of “NWS observations only”

CALMET data for the specific assessments for the Northeast visibility were provided. The

analysis indicated good model performance using EPA’s IWAQM Phase 2 report’s statistical

methods, especially in dealing with wind direction bias issues. Vermont’s review also pointed to

previous findings as part of the NESCAUM’s meteorological data development (see footnote 6),

indicating that the MM5 only data platform, which did not incorporated the observed wind

fields, did have certain biases, except along the coastline. Given the performance re-evaluation

conducted by Vermont DEC using EPA’s recent guidance and the additional evaluations EPA is

still to undertake on their recommendation of using a “hybrid” data base, we have determined

that the Vermont NWS only CALMET data base is still appropriate to be used as one of the data

sets in the visibility analysis of New York BART sources. We understand that at this point EPA

and FLMs do not consider this data as conforming to their latest guidance, but our purpose in

recommending its use is again to envelope the set of meteorological conditions which could lead

to the maximum impacts even with the same data year, barring any showing that the evaluation

by Vermont DEC is inappropriate. 

Since our initial modeling protocol at the end of 2007, a revised 2002 CALMET data

base has been created which incorporates the MANE-VU MM5 wind field as well as NWS

observations. This new data base is in accord with the latest EPA guidance and has been
11A Study of the Multiple Year Variation of Air Quality Impacts Predicted by the

CALPUFF Dispersion Model. Paper no. 69232 by Daniel Riley of Vermont DEC. Can be

provided upon request.

-6-

reviewed and found appropriate by staff from the Fish and Wildlife Service. It covers all the

Class I areas to be modeled for New York sources on a refined 4km grid basis. Details of the

procedures used are provided in the attached AECOM consultants April, 2009 document. It is

important to note that the acceptance of this one year data base by the FLMs is predicated on a

set of conditions which have been incorporated herein. That is, in lieu of using the

recommended three years of meteorological data for BART analysis, certain “conservative”

steps must be undertaken in the review of impacts, as detailed below. 

EPA’s modeling guidelines’ recommendation to use minimum of three years of

meteorological data in assessing Class I area impacts in permitting actions allows the

consideration of potential yearly variability in meteorological conditions in calculating expected

worst case impacts. However, given the nature of the visibility thresholds to be used for these

analysis, the level of importance that might be assigned to the modeling results as one of five

criteria in BART determinations, and the practical constrains in meeting EPA deadlines for

BART submissions, we conclude that specific BART analysis for New York sources can

adequately rely on the revised AECOM’s hybrid MM5 and Vermont “NWS-only” data bases. 

On the other hand, the processing of additional years of data through the CALMET processor

could potentially be required if a source chooses to deviate substantially from the

recommendations in this protocol. We emphasize that, to the extent possible, the recommended

setting for CALMET in EPA’s August 31, 2009 memo should be used in these BART analysis

cases. In addition, in lieu of using three years of data, our review of the “best” BART alternative

for each of the sources could also consider the effects of meteorological data variability on

CALPUFF impacts using the results of an multi year data analysis of CALPUFF impacts

conducted by Vermont DEC staff11. That analysis used five years (1990-1994) of meteorological

data and provided average indicators of variability in impacts predicted by CALPUFF, including

visibility, at the Lye Brook Class I area. 

 DEC has obtained both the Vermont and AECOM data bases for 2002 and will provide

these to the BART sources. In order to obtain this data, sources will have to submit a 1terabite

or larger external hard drive to NYSDEC staff. 

4) Visibility Index, Thresholds and CALPOST Outputs. The NESCAUM analysis followed

the BART Guidelines in relying on the deciview measure of visibility impacts and we

recommend the same measure for the New York source specific analysis. As noted in the

Regional Haze rule and BART guidelines, the deciview was developed to provide a visibility (or

haziness) index which is linear with respect to perceived visual change and fractional change in
12 “Development and Application of a Standard Visual Index”, Pitchford and Malm

(1994), Atmospheric Environment, Vol.28, No.5, pp 1049-1054. 

-7-

extinction coefficient and is, thus, related to both these quantities12. Therefore, a change in

visibility in terms of deciview can be related to other measures such as extinction coefficient

preferred by the FLMs. As for comparison thresholds, the BART guidelines suggest certain

deciview levels in terms of both exemption modeling and “cause” or “contribute” measures in

BART determinations, but leave it to the state agency’s discretion to determine appropriate

levels. As noted previously, New York has adopted a low 0.1dv level specifically for exemption

modeling, but no other single measure has been set for source specific BART assessments. 

Thus, for any modeling to demonstrate a unit is exempt from any further assessments, a source

can provide a showing that they meet the 0.1 dv level under existing conditions. In doing so,

however, it is important to note that although EPA guidance allow the use of the 8th highest

impacts be used for this demonstration, this allowance is only acceptable if the analysis strictly

relies on the appropriate modeling approach; for example, three years of meteorological data

must be used. However, the FLMs have agreed to the use of the single 2002 year data by

AECOM only to the extent that a) the maximum visibility impacts are used for comparison to the

thresholds and b) the 20% best background conditions are used (see below). 

For modeling to demonstrate the best BART alternative for a given unit, we have defined

further criteria in order to fully understand the relevant impacts within the context of the five

factors to be used for such determinations. That is, although we will use the maximum impacts

to gauge the net improvements in visibility, we are also seeking a set of impacts from a source in

order to get a more comprehensive understanding of these impacts in our BART determinations.

As noted in the EPA BART guidelines, one “bright line” value might not be appropriate. We

recognize that EPA has recommended levels at 1dv and 0.5dv for determination of “cause” and

“contribute” in BART assessments, while the FLAG document has identified the corresponding

“equivalent” extinction coefficient values for their decision making. Thus, instead of using a

single threshold, we recommend the following CALPUFF post processing of visibility impacts to

assist our determination of the best BART alternative for each source:

i) the maximum and 98% (or 8th highest) 24 hour visibility impact for the pre and post BART

control source emissions for each alternative. 

ii) 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.

iii) for facilities with more than one BART eligible unit, the cumulative visibility maximum

impacts of all units. 

These impacts should provide the individual contribution of SOx, NOx and particulate

emissions. The CALPUFF impact calculations must use the same scheme for the pre and post
13 In a July 19, 2006 internal EPA memorandum from Joseph Paisie to Kay Prince of

EPA Region 4, EPA clarified that it has given States the choice between using the 20% best days

or the annual average natural background levels for BART net visibility comparison purposes. 

However, we believe, for the same arguments set forth by NESCAUM, that the use of the 20%

best values are appropriate for our BART determinations. This is especially true for comparisons

of 24 hour visibility impacts.

14Baseline and Natural Background Visibility Conditions, dated December, 2006,

Prepared by NESCAUM and available on their webpage. 

-8-

control scenarios in all these calculations. In addition, these visibility impacts should be

calculated relative to the 20% best natural background levels, similar to the approach used by

NESCAUM, and as noted in the BART rule preamble. This is notwithstanding EPA’s allowance

for states to chose the annual levels.13 As noted above, the FLMs acceptance of the use of a

single year of “hybrid” meteorological data is also contingent on the use of these background

conditions. 

The NESCAUM document on determining natural background levels references EPA’s

guidance on the subject and also provides an alternative approach to the EPA “default”

assumptions and calculations14. This alternative scheme updates the calculation of the extinction

coefficient which is in line with the formula recommended in the FLAG guidance. This is the

“new” IMPROVE equation used for extinction coefficient calculations, with the corresponding

input parameters as defined in the 6/27/08 FLAG revised document (see footnote 4). The main

input parameters recommended by the NPS/FLM representing 20% best natural conditions as

input to the CALPOST program to calculate relative BART source impacts for the pre and post

BART emissions at the Class I areas are provided in the following table:

Class I Area-20% Best

Natural Conditions 

(NH4)2SO4

μg/m3

NH4NO3

μg/m3

OM

μg/m3

EC

μg/m3

Soil

μg/m3

CM

μg/m3

Sea Salt

μg/m3

Rayleigh

Mm-1

Lye Brook Wilderness, VT 0.05 0.03 0.36 0.01 0.09 0.63 0.01 11

Brigantine Wilderness, NJ 0.12 0.04 0.86 0.01 0.24 1.73 0.04 12

Acadia National Park, ME 0.09 0.03 0.68 0.01 0.10 0.94 0.03 12

Great Gulf and Presidential

Range Wilderness NH 

0.09 0.04 0.56 0.01 0.10 1.05 0.02 11

Dolly Sods and Otter Creek

Wilderness, WV

0.10 0.05 0.80 0.01 0.17 0.96 0.01 10

Additional input data, such as the monthly relative humidity factors, are also presented in

the FLAG document and should be used. One further clarification needs to be made with respect

to the CALPOST program to be used in generating the visibility impacts. Although EPA

identified CALPOST version 5.8 as the “official” EPA recognized version for general use, that

version does not provide visibility impacts per the latest FLM/EPA specifications and must be

further post processed. However, FLMs have recommended the use of CALPOST Version 6.221

(Method 8, Mode 5) which performs the correct calculations with the new IMPROVE equation. 
-9-

This version of CALPOST also includes more accurate calculations of the new IMPROVE

equation than the VISTAS spreadsheet used previously in BART analysis. Thus, we recommend

that this version of CALPOST be applied and the FLAG switch chosen which automatically sets

the parameters to correspond to Method 8, Mode 5 of the model. 

These data should allow the calculation of the pre and post BART control alternatives

and emissions relative to natural background values which are the aim of the regional haze

reduction program. These will allow NYSDEC staff to determine the efficacy of the control

measure which bests fit the requirements of the regional visibility improvements due to sources

which have been identified to cause or contribute to Class I visibility degradation.

5) Pollutants and Emission Rates. The BART Guidelines, as well as a follow-up EPA’s

internal memorandum (in footnote 9), recommend modeling the emissions of NOx, SO2 and

direct PM in concert in the CALPUFF analysis to account for the nonlinear chemical interaction

of these pollutants and their species. The emissions of PM should include both PM10 and

PM2.5 emissions. In instances where a source does not have information on PM2.5 emissions

(i.e. condensible fraction), references available thought EPA (AP-42 factors) or on NPS’s

webpage could be used (see FLAG report guidance). The relative contribution of the individual

pollutants to the total visibility impacts in terms of deciview measure should be presented to

allow the determination of relative significance of the pollutant emissions and possible control

measures. The emission rates which must be used for New York source assessments are the

maximum actual daily values which are representative of the source’s normal operations

(excluding only startup and shut down conditions). As noted in the Preamble to the BART rule,

the use of average daily actual rate could easily underestimate the daily maximum visibility

projections and is not recommended. 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. The BART guidelines note that this maximum rate can be representative of the

highest emitting day of the meteorological period used. However, we do not follow this

approach since the meteorological period covers only the single year 2002 and, more

importantly, maximum daily actual rates should be defined a priori to the determination of

maximum visibility impacts and not in reverse.

We recognize that there are hourly emission data available for certain of the BART

eligible sources and for certain pollutants (i.e. EGUs for NOx and SO2) and some of this was

used in the NESCAUM preliminary analysis. Although hourly emission data might be more

reflective of the corresponding short term aspects on visibility impacts, we are not

recommending its use within this “default” protocol set of conditions. In order for such

emissions to properly represent the potential visibility impacts under all set of meteorological

conditions simulated within CALPUFF, these emissions must be shown to be consistent and

static with both daily operations as well as seasonal fluctuations during a long term period of

operations of a facility. We do not believe such a demonstration can be readily made by sources. 

On the other hand, if the BART-eligible sources do have certain demonstrated limitations on

operations (such as “peaking” operations for a minor part of the year), these considerations
-10-

should be presented within the discussions of the set of modeling results recommended above

(and any additional results a source chooses to submit) and the five factor analysis for BART

determinations. 

The emission rates as well as the stack parameters used in the NESCAUM modeling

were submitted to each BART eligible source for confirmation and any revisions. These data

verifications or modifications have been submitted and will be reviewed by DEC staff. In

instances where the maximum daily emission rate for a pollutant cannot be determined, then the

maximum allowable emission rate must be used in accord with EPA and DEC modeling

guidelines.

III. Summary. Each of the New York sources subject to the BART requirements through the

provisions of the Regional Haze rule must submit a net visibility improvement analysis at a set

of federal Class I areas, identified previously by an initial modeling perform for NESCAUM

sources. These assessments will assist NYSDEC staff in the determination of the appropriate

source specific alternative for possible BART control measures. The analysis should follow the

recommendations outlined in the sections above, with any minor deviations to be discussed with

NYSDEC staff before implementation. Any significant deviations from these recommendations

will require the submission of a source specific analysis protocol which must be approved by

NYSDEC staff, with input from USEPA Region II and the FLMs prior to submission of the

visibility assessment.
APPENDIX E

MODELING INPUT AND OUTPUT FILES