1 **New York State Department of Environmental Conservation Best Available Retrofit Technology Determination**  Facilit y Bowline Point Generating Station Location Haverstraw, NY

Rockland County Permit I D 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. W as 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 an y visibility

- impairing pollutant. In accordance with BART requirements, each BART

- eligible facility must perform a BART anal ys is of controls for sulfur dioxide, nitrogen oxides and particulate matter. This anal ys is takes into account such factors as the cost of controls, energy and non

- air qualit y 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 im provement in visibility which may reasonabl y be anticipated to result from the use of such technology. This document reflects the Department’s determination of what level of controls constitutes BART for this facility ’s BART

- eligible emission source ( s )

. Each anal ys is and determination was submitted to the Federal Land Managers (FLMs) for their review in accordance with Regional Haze State Implementation Plan (SI P) requirements. Comments received from the FLMs on each determination will be included with its submission. The Department is now working to expeditiously modify this facilit y’s Title V permit to include the enforceable BART limits. Specific parameters and limits that are used as the technical bases of BART determinations, such as sulfur limi ts, the installation of controls, and operational limitations, will be incorporated into each facility 's permit in enforceable conditions. These permit modifications will be submitted to the U.S. Environmental Protection Agency (EPA) as SI P revisions once complete.2

**II. BART**  **Analysis Summary** Mirant submitted a BART anal ys is 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 are therefore included in the analy sis: **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 h as 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 frequentl y than No. 6 oil; in 2009, this unit operated only 568 hours (about 95

— o r 17 percent

— of which were No. 6 oil firing). O peration commenced in 197 4

. **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

— or 13 percent

— of which were No. 6 oil firing). O peration commence d in 1974. Each of these boilers operates very infrequently . They

are essentiall y regarded as “peaking units” under current (and expected future) operations. Because of this infrequent operation, these units have very low actual air emission rates relat ive to the boiler size. A summary

of the analy sis’ findings for each pollutant are as follows:

 SO 2 Mirant Bowline alread y burns No. 6 fuel oil with a sulfur content of onl y 0.37 percent. SO 2 emissions from natural gas are minimal. Mirant examined the technical feasibility of three potential SO 2 post
- combustion control options: wet flue gas desulfurization (FGD) s ys tem, spray dry er absorber, and dry injection. Wet FGD was determined to be the onl y technicall y feasible option. Under a base case of full No. 6 oil operation, the control efficiency for w et FGD on each boiler would be 90 percent. Baseline emissions were determined from the 2008

- 2009 calendar ye ars, which also represent anticipated operation over the next few y ears. Mirant 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 w et FGD unit at Bowline’s baseline emissions produce a cost

- effectiv eness of $498,825 /ton for Boil er 1 and $550,308 /ton for Boiler 2.3

Mirant 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.

 NO x Boiler 1 currentl y operates with Coen Lo w - NOx Reduced Emissions & Advanced Combustion Hardware (LNREACH) high

- pressure simplex nozzle sy stem for NO x control under oil

- firing operation. Boiler 2 controls NO x through an LNREACH high

pressure return nozzle system for oil

- firing, as well as over fire air (OFA) and windbox flue gas recirculation (FGR). A number of additional NO x control options were anal yz ed, including combustion controls, post

- combustion controls, and combinations of controls. The technically feasible options are: combustion opt imization with oversized burners, new L NREACH steam atomized burners, addition of separated overfire air (SOFA) to combustion optimization, FGR, gas reburn, selective catal yt ic reduction (SCR), selective non

catal yt ic reduction (SNCR), fuel lean amine rebu rn emulsion (FLARE), and process optimization modeling system (POMS) or neural network (NN). A summary of the se potential controls along with expected control efficiencies are represented in T able 1 below for Boilers 1 and 2 , again using full No. 6 fuel o il operation as a baseline. **Control Option Efficiency** **B o** **i l** **e r** **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%**B o** **i l** **e r** **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 + F L GR + 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 determined from the 2008

- 2009 calendar ye ars 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 & Lund y. Sargent & Lund y prepared cost estimates based on industry

- based cost an d performance data for t ypical units, and include retrofits likel y required for Bowline. The potential costs of control are display ed in Table 2.

Control Option Annualized Cost Avg Cost (per

ton removed)**B o** **i l** **e r** **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**B o** **i l** **e r** **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 + F L GR + 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, Mirant contends that none are economically

feasible. Mirant requests that the current NO x controls be accepted as BART.

 PM Mirant 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 analy zed included additional combustion controls to minimize particulate formation, an electrostatic precipitator (ESP), and fabric5

filters. Additional combustion controls and fabric filters were determined to be technicall y infeasible for these boilers

. The c ontrol costs for an ESP unit were based on EPA’s Control Cost Manual. The average cost effectiveness of a n ESP sy stem with estimated control efficiency of 63 percent was $5,965,524 per ton

. Mirant 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 Mirant’s minimizing the benefits of a 0.5 deciview improvement n or its comparisons to unrelat ed determinations in other states, but the Department feels the “no control” conclusion is otherwise justified.)

 SO 2 The Department accepts the current fuel sulfur limit of 0.37 percent b y weight as BART for SO 2 . This is in line with the EPA presumptive limit for sulfur in fuel of 1.0 percent or less by weight (Appendix Y, Section I V.E.4, “SO 2 limits for Utility Boilers”). Furthermore, Mirant demonstrated that additional SO 2 reduction technologies were technical ly

or economically

infeasible

.

 NO x The Department accepts the finding that no further control is required as BART for NO x . Mirant demonstrated that all technicall y feasible controls were economically prohibitive.

 PM The Department accepts the finding that no further control is required a s 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 BA RT.