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New York State Department of Environmental Conservation 

Best Available Retrofit Technology Determination 

Facility Bowline Point Generating Station 

Location Haverstraw, NY 

Rockland County 

Permit ID 3-3922-00003 

Source Category Fossil-fuel fired steam electric plants 

of more than 250 mmBtu/hr heat input 

I. Introduction 

The above referenced facility contains at least one emission source that falls under the 

requirements of the federal Best Available Retrofit Technology (BART) rule under 40 CFR Part 

51 and Appendix Y, and the New York State BART regulation as codified under 6 NYCRR Part 

249. These requirements affect an emission source which fulfills the following criteria: 

1. Falls within one of 26 specific source categories, 

2. Was not in operation prior to August 7, 1962 and was in existence on August 7, 1977, or 

underwent reconstruction between August 7, 1962 and August 7, 1977, and 

3. Has a potential to emit (collectively, with other emission sources at the facility which 

fulfill items 1 and 2) of 250 tons per year or more of any visibility-impairing pollutant. 

In accordance with BART requirements, each BART-eligible facility performed a BART 

analysis of controls for sulfur dioxide, nitrogen oxides and particulate matter. This analysis took 

into account such factors as the cost of controls, energy and non-air quality environmental 

impacts of compliance, any existing pollution control technology in use at the source, the 

remaining useful life of the source, and the degree of improvement in visibility which may 

reasonably be anticipated to result from the use of such technology. 

This document summarizes the reasoning behind the Department’s BART determination, 

including the level of controls and emission limits that constitute BART for this facility’s eligible 

emission source(s). Each analysis and BART determination was submitted to the Federal Land 

Managers (FLMs) for their review in accordance with Regional Haze State Implementation Plan 

(SIP) requirements. Comments received from the FLMs on this determination will be included 

with its official submission to the U.S. Environmental Protection Agency (EPA). 

The Department has modified this facility’s Title V permit to include the enforceable BART 

limits. Following an initial permit modification process that ceased prior to permit issuance, the 

modifications were re-proposed in New York State’s Environmental Notice Bulletin on May 23, 

2012. Upon completion of this public notice period, the modified permit was submitted to EPA 

for review on June 26, 2012. The final modified permit was issued on June 28, 2012. This 

permit is now being submitted to EPA as a revision to the New York Regional Haze SIP. 

 
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II. BART Analysis Summary 

Mirant (now GenOn Energy) submitted a BART analysis for the Bowline Point Generating 

Station to the Department, dated September 29, 2010. The following emission sources had 

previously been identified as BART-eligible and were therefore included in the analysis: 

Boiler No. 1 – Emission Unit 1-00001; Emission Source 00UN1 

• This unit is a Combustion Engineering tangentially-fired boiler with a maximum heat 

input of 5,546 mmBtu/hr. This boiler/turbine unit has a nominal electric generating 

capacity of 570 MW and can fire either natural gas, or No.6 fuel oil with a maximum 

sulfur content of 0.37 percent. Natural gas is used much more frequently than No. 6 oil; 

in 2009, this unit operated only 568 hours (about 95 hours, or 17 percent, of which were 

No. 6 oil firing). Operation commenced in 1974. 

Boiler No. 2 – Emission Unit 1-00002; Emission Source 00UN2 

• A Babcock & Wilcox opposed wall-fired boiler with a maximum heat input of 5,374 

mmBtu/hr. This unit can fire natural gas or No. 6 fuel oil (with a maximum sulfur 

content of 0.37 percent). Natural gas is used much more frequently than No. 6 oil; in 

2009, this unit operated only 187 hours (about 24 hours, or 13 percent, of which were No. 

6 oil firing). Operation commenced in 1974. 

Each of these boilers operates very infrequently. They are essentially regarded as 

“peaking units” under current (and expected future) operations. Because of this 

infrequent operation, these units have very low actual air emission rates relative to the 

boiler size. 

A summary of the analysis’ findings for each pollutant are as follows: 

• SO2

Bowline already burns No. 6 fuel oil with a sulfur content of only 0.37 percent. SO2

emissions from natural gas are minimal. 

GenOn examined the technical feasibility of three potential SO2 post-combustion control 

options: wet flue gas desulfurization (FGD) system, spray dryer absorber, and dry 

injection. Wet FGD was determined to be the only technically feasible option. Under a 

base case of full No. 6 oil operation, the control efficiency for wet FGD on each boiler 

would be 90 percent. 

Baseline emissions were determined from the 2008-2009 calendar years, which also 

represent anticipated operation over the next few years. GenOn utilized EPA’s Coal 

Utility Environmental Cost (CUECost) spreadsheet model for estimating control costs, 

with adjustments to reflect No. 6 oil firing rather than coal firing. The annualized costs 

of a wet FGD unit at Bowline’s baseline emissions produce a cost-effectiveness of 

$498,825/ton for Boiler 1 and $550,308/ton for Boiler 2. 
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GenOn therefore requests that the current use of 0.37 percent sulfur No. 6 oil be accepted 

as BART for SO2 for Boilers 1 and 2. 

• NOx

Boiler 1 currently operates with Coen Low-NOx Reduced Emissions & Advanced 

Combustion Hardware (LNREACH) high-pressure simplex nozzle system for NOx

control under oil-firing operation. Boiler 2 controls NOx through an LNREACH highpressure return nozzle system for oil-firing, as well as overfire air (OFA) and windbox 

flue gas recirculation (FGR). 

A number of additional NOx control options were analyzed, including combustion 

controls, post-combustion controls, and combinations of controls. The technically 

feasible options are: combustion optimization with oversized burners, new LNREACH 

steam atomized burners, addition of separated overfire air (SOFA) to combustion 

optimization, FGR, gas reburn, selective catalytic reduction (SCR), selective noncatalytic reduction (SNCR), fuel lean amine reburn emulsion (FLARE), and process 

optimization modeling system (POMS) or neural network (NN). A summary of these 

potential controls along with expected control efficiencies are represented in Table 1 

below for Boilers 1 and 2, again using full No. 6 fuel oil operation as a baseline. 

Control Option Efficiency

Boiler 1

Combustion optimization with oversized burners + BOOS + natural gas

reburn + NN 63%

Combustion optimization with oversized burners + BOOS + SOFA + NN 55%

Combustion optimization with oversized burners + BOOS + SNCR + NN 50%

Combustion optimization with oversized burners + BOOS + FLARE + NN 65%

SCR + ESP + Trona injection system 90%

Combustion Optimization + SOFA + FLARE 65%

Boiler

2

Combustion optimization with existing hardware + natural gas reburn + NN 69%

Combustion optimization with existing hardware + relocated/modified

OFA + NN 58%

Combustion optimization with existing hardware + FLARE + NN 72%

Combustion optimization with new steam atomizers + modified existing

OFA + FLGR + NN 72%

Combustion optimization with new steam atomizers + modified existing

OFA + SNCR + NN 62%

SCR + ESP + Trona injection system 90%

Combustion Optimization + FLARE 65%
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Baseline emissions were again determined from the 2008-2009 calendar years and 

utilized for calculating the cost effectiveness of the above control technologies. These 

NOx control costs were based on a site-specific study performed by Sargent & Lundy. 

Sargent & Lundy prepared cost estimates based on industry-based cost and performance 

data for typical units, and include retrofits likely required for Bowline. The potential 

costs of control are displayed in Table 2. 

Control Option Annualized

Cost

Avg Cost (per

ton removed)

Boiler 1

Combustion optimization with oversized burners

+ BOOS + natural gas reburn + NN $2,723,170 $65,509

Combustion optimization with oversized burners

+ BOOS + SOFA + NN $1,048,780 $26,265

Combustion optimization with oversized burners

+ BOOS + SNCR + NN $2,536,835 $73,604

Combustion optimization with oversized burners

+ BOOS + FLARE + NN $3,775,535 $65,058

SCR + ESP + Trona injection system $10,953,105 $97,861

Combustion Optimization + SOFA + FLARE $2,307,184 $54,080

Boiler

2

Combustion optimization with existing hardware

+ natural gas reburn + NN $2,650,081 $137,528

Combustion optimization with existing hardware

+ relocated/modified OFA + NN $975,691 $56,664

Combustion optimization with existing hardware

+ FLARE + NN $2,663,846 $132,866

Combustion optimization with new steam

atomizers + modified existing OFA + FLGR + NN $2,806,832 $139,998

Combustion optimization with new steam

atomizers + modified existing OFA + SNCR + NN $3,482,693 $199,582

SCR + ESP + Trona injection system $10,953,105 $247,972

Combustion Optimization + FLARE $2,307,184 $126,562

Given the average cost per ton values of the proposed technologies, GenOn contends that 

none are economically feasible. GenOn requests that the current NOx controls be 

accepted as BART. 

• PM 

GenOn notes that the visibility impacts of its particulate emissions are relatively low--PM 

contributed to less than 10 percent of the total visibility impact on Class I areas for each 

case modeled. The PM reduction options analyzed included additional combustion 

controls to minimize particulate formation, an electrostatic precipitator (ESP), and fabric 
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filters. Additional combustion controls and fabric filters were determined to be 

technically infeasible for these boilers. 

The control costs for an ESP unit were based on EPA’s Control Cost Manual. The 

average cost effectiveness of an ESP system with estimated control efficiency of 63 

percent was $5,965,524 per ton. 

GenOn requests that current operations be deemed BART for PM. 

III. BART Determination 

The Department finds that the following shall constitute BART for Bowline Point Generating 

Station Boilers 1 and 2. (Note that the Department does not agree with GenOn’s minimizing the 

benefits of a 0.5 deciview improvement nor its comparisons to unrelated determinations in other 

states, but the Department feels the “no control” conclusion is otherwise justified.) 

• SO2

The Department accepts the current fuel sulfur limit of 0.37 percent by weight as BART 

for SO2. This is in line with the guidance provided by EPA for sulfur in fuel of 1.0 

percent or less by weight (Appendix Y, Section IV.E.4, “SO2 limits for Utility Boilers”). 

Furthermore, GenOn adequately demonstrated that additional SO2 reduction technologies 

were technically or economically infeasible. 

• NOx

The Department accepts the finding that no further control is required as BART for NOx. 

GenOn demonstrated that all technically feasible controls were economically prohibitive. 

Following additional discussions and the submission of GenOn’s NOx RACT plan (dated 

December 21, 2011, with a follow-up letter on February 3, 2012), the Department and 

GenOn agreed to NOx limits of 0.15 lb/mmBtu when firing gas, and 0.25 lb/mmBtu when 

firing oil. These limits are averaged over 24 hours during the ozone season and 30 days 

during the non-ozone season. GenOn is also accepting a limit on the amount of fuel oil 

burned of 3.1 million barrels during the ozone season and 4.6 million barrels during the 

non-ozone season (which will also benefit SO2 emissions). GenOn has been granted a 

July 1, 2014 compliance deadline, which is still within the required five years following 

EPA SIP approval. 

• PM 

The Department accepts the finding that no further control is required as BART for PM. 

The minimal impact of the boilers’ PM emissions was evident through the $5.97M per 

ton control cost of an ESP. The Bowline Point facility will continue to comply with the 

existing permit limit for particulates of 0.1 lb/mmBtu to satisfy BART.