### 1 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 Retr ofit Technology (BART) rule under 40 CFR Part 51 and Appendix Y, and the New York State BA RT regulation as codified under 6 NYCRR Part 249. These requirements affect an emission s ource which fulfills the following criteria:

1. Falls within one of 26 sp ecific 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 ot her 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 particul ate matter. This analysis took

into account such factors as the cost of c ontrols, energy and non-air quality environmental impacts of compliance, any existing pollution co ntrol technology in use at the source, the remaining useful life of the source, and the de gree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.

This document summarizes the reasoning be hind the Department’s BART determination, including the level of cont rols 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 perm it 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.

### 2 II. BART Analysis Summary

Mirant (now GenOn Energy) submitted a BART analysis for the Bowline Point Generating Station to the Department, dated Septembe r 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 tange ntially-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 natu ral 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 boi ler 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 hour s, or 13 percent, of which were No. 6 oil firing). Opera tion commenced in 1974.

Each of these boilers operate s very infrequently. They are essentially regarded as “peaking units” under current (and expected future) operations. Because of this infrequent operation, these units have very lo w actual air emission ra tes relative to the

boiler size.

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

• SO 2



### Bowline already burns No. 6 fuel oil with a sulfur content of only 0.37 percent. SO 2 

### emissions from natural gas are minimal.

GenOn examined the technical f easibility of three potential SO 2 

### post-combustion control options: wet flue gas desulfurization (FGD) system, spray dryer absorber, and dry injection. Wet FGD was determined to be th e only technically feas ible option. Under a base case of full No. 6 oil operation, the cont rol 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) spread sheet model for estimating control costs, with adjustments to reflect No. 6 oil firing ra ther 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.

### 3 GenOn therefore requests that the current use of 0.37 percent sulfur No. 6 oil be accepted

as BART for SO 2 

### for Boilers 1 and 2.

• NO

x



### Boiler 1 currently operates with Coen Low-NO

x 

### Reduced Emissions & Advanced Combustion Hardware (LNREACH) high-pr essure simplex nozzle system for NO

x 

### control under oil-firing operation. Boiler 2 controls NO

x 

### through an LNREACH highpressure return nozzle system for oil-fi ring, as well as overfire air (OFA) and windbox flue gas recirculation (FGR).

A number of additional NO

x 

### control options were analyzed, including combustion controls, post-combustion cont rols, and combinations of controls. The technically feasible options are: com bustion optimization with overs ized burners, new LNREACH steam atomized burners, addition of separa ted overfire air (SOFA) to combustion optimization, FGR, gas reburn, selectiv e catalytic reduction (SCR), selective noncatalytic reduction (SNCR), fuel lean am ine reburn emulsion (FLARE), and process optimization modeling system (POMS) or ne ural 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 EfficiencyBoiler1 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%Boiler2 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%

### 4 Baseline emissions were again determin ed from the 2008-2009 calendar years and utilized for calculating the co st effectiveness of the above control technologies. These

NO

x 

### control costs were based on a site-spe cific study performed by Sargent & Lundy. Sargent & Lundy prepared cost estimates ba sed 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)Boiler1 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 $54,080Boiler2 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 techno logies, GenOn contends that none are economically feasible. GenOn requests that the current NO

x 

### controls be accepted as BART.

• PM

GenOn notes that the visibility impacts of its particulate em issions are relatively low--PM contributed to less than 10 per cent 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 precipitato r (ESP), and fabric

### 5 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 opera tions be deemed BART for PM.

III. BART Determination

The Department finds that the following sha ll constitute BART for Bowline Point Generating Station Boilers 1 and 2. (Note that the Depart ment does not agree with GenOn’s minimizing the benefits of a 0.5 deciview improve ment nor its comparis ons to unrelated determinations in other states, but the Department f eels the “no control” conclusi on is otherwise justified.)

• SO 2



### The Department accepts the current fuel sulf ur limit of 0.37 percent by weight as BART

for SO 2 

### . This is in line with the guidance pr ovided by EPA for sulfur in fuel of 1.0 percent or less by weight (A ppendix Y, Section IV.E.4, “SO 2 

### limits for Utility Boilers”). Furthermore, GenOn adequately demonstrated that additional SO 2 

### reduction technologies were technically or economically infeasible.

• NO

x



### The Department accepts the finding that no fu rther control is requi red as BART for NO

x 

### . GenOn demonstrated that all te chnically feasible controls we re economically prohibitive. Following additional discussions and the submission of GenOn’s NO

x 

### RACT plan (dated December 21, 2011, with a follow-up letter on February 3, 2012), the Department and GenOn agreed to NO

x 

### limits of 0.15 lb/mmBtu when firing gas, and 0.25 lb/mmBtu when firing oil. These limits are averaged ove r 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 SO 2 

### emissions). GenOn has been granted a July 1, 2014 compliance deadline, which is sti ll within the required five years following EPA SIP approval.

• PM

The Department accepts the finding that no furt her 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 Poin t facility will continue to comply with the existing permit limit for particulates of 0.1 lb/mmBtu to satisfy BART.