# NRG Energy

Oswego Power Station Reasonably Available Control Technology and Best Available Retrofit Technology Engineering Evaluation

FINAL REPORT

Prepared by: Sargent & Lundy LLC Chicago, Illinois



## July 26, 2010NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

Approval and Certification Page NRG

OSWEGO GENERTING STATION UNITS 5 & 6

RACT / BART ENGINEERING EVALUATION

ISSUE SUMMARY, APPROVAL AND CERTIFICATION PAGE

This is to confirm that the this report has been prepared, reviewed and a pproved in accordance with Sargent & Lundy’s Standard Operating Procedure SOP-0405, which governs the preparation, review and approval of Miscellaneous Engin eering and Design Deliverables, which is part of our Quality Management System.

Issue Purpose Issue Date Prepared By Reviewed By Approved By

Record 06-16-2010 D Helm G Dusatko K Snell S McHone

FINAL 07/26/2010 D Helm G Dusatko K. Snell S. McHoneNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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ES-1 EXECUTIVE SUMMARY

NRG owns and operates the Oswego Power Station (Oswego Station) located on a 93-acre site in Oswego, New York, along the south shore of Lake Ontario. The station consists of two (2) oilfired steam electric generating units, four retir ed units, and the supporting ancillary equipment and operations needed for operation of the boile rs, including an oil storage tank farm and
associated rail facilities.

Oswego Units 5 & 6 are Foster-Wheeler boilers desi gned to fire No. 6 fuel oil. The units are rated at 870 MW (gross) each with 6,300,000 lb/hr main steam flow at 2,480 psig pressure and 1,005 o F temperature, and a reheat flow of 5,722,0 00 lb/hr at 705 psig outlet pressure and 1,005

o F. Both units are equipped with an electrostatic precipitator (ESP) for particulate control.

The federal Clean Air Act (CAA) requires states w ith nonattainment areas (i.e., areas that do not meet the federal national ambient air quality sta ndards) to develop a State Implementation Plan (SIP) to “provide for the implementation of all reasonably available control measures as expeditiously as practicable (including such reduc tions in emissions from existing sources in the area as may be obtained through the adoption, at a minimum, of reasonably available control technology) and shall provide for attainment of the national primary ambient air quality standards.” (CAA §172(c)(1)). EPA’s rules impl ementing §172(c)(1) of the CAA require states to demonstrate, through a SIP submission, th at their RACT requirements address emissions contributing to nonattainment, and effectively work toward achieving compliance with the applicable NAAQS. The New York RACT rules ar e located in 6 NYCRR 227-2. In general, the RACT rules limit NOx emissions from combustion sources and are designed to address ozone
nonattainment.

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional Haze Regulations and Guidelines for Best Avai lable Retrofit Technology Determinations” (the “Regional Haze Rule” 70 FR 39104). The Re gional Haze Rule requires states to develop programs to assure reasonable progress toward meeting the national goal of preventing any future, and remedying any existing, impairment of visibility in Class I Areas. The Regional Haze Rule requires states to submit a plan to implem ent the regional haze requirements (the Regional Haze SIP). The Regional Haze SIP must provi de for a Best Available Retrofit Technology (BART) analysis of any existing stationary facilit y that might cause or contribute to impairment of visibility in a Class I Area.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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ES-2 BART is required for any BART-eligible sour ce that emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I Area. Guidelines for making BART determinations ar e included in Appendix Y of 40 CFR Part 51
“Guidelines for BART Determinations Under the Regional Haze Rule,” (the “Appendix Y Guidelines”). States are required to use the Appendix Y Guidelines to make BART
determinations for fossil-fuel-fi red generating plants having a to tal generating capacity in excess of 750 MW. Because the generating capacity of BART-eligible sources at the Oswego Station is greater than 750 MW, from a federal perspective, conformance with the Appendix Y Guidelines is required.

The BART determination process described in the Appendix Y Guidelines includes the following
steps:

Step 1. Identify All Available Retrofit Control Technologies. Step 2. Eliminate Technically Infeasible Options. Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. Step 4. Evaluate Impacts and Document the Results. Step 5. Evaluate Visibility Impacts.

This engineering report was prepared to support the Oswego Unit 5 & 6 RACT compliance evaluation and BART determination, focusing on the control of NOx emissions from both units.
This evaluation follows the BART determinati on process described the Appendix Y Guidelines, and includes the information and evaluations required by Steps 1 through 4 of the BART determination process. The report reviews base line NOx emissions from each units, identifies and evaluates the technical feasibility of potentia l NOx retrofit control options, and provides budgetary cost estimates and calculates the cost -effectiveness of each technically feasible NOx control technology. Tables ES- 2 and ES-2 provide a summary of the technically feasible NOx control options, including: (1) annual emissi on reductions achievable with each technology (compared to baseline annual NOx emissions); (2 ) total annual costs associated with the installation and operation of each technology; and (3) the average co st-effectiveness of each technology.

Based on the evaluation of capital costs, operating costs, and annual emission reductions included herein, none of the technically feasible and ava ilable NOx control options are cost effective on Oswego Units 5 & 6. Several site-specific factor s contribute to this result. First, there are significant capital requirements associated with the post-combustion control systems, including selective catalytic reduction (SCR), fuel lean gas reburn (FLGR), and selective non-catalytic reduction (SNCR). Both equipment costs and retrofit challenges contribute to these capital costs. Capital costs of post-combustion control range from approximately $11.3/kW-gross (SNCR withNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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ES-3 combustion control modifications) to as high as $122.8/kW-gross (SCR). Capital costs associated with combustion control system modifications are significantly less ranging from $2.8/kW-gross (with pressure atomization) to $7.0/ton (with steam atomization).

More importantly, baseline annual NOx emissions from both units are only in the range of approximately 240 tpy. Baseline annual NOx emissions are low because of the low capacity factors achieved by both units during the baseline period. Both units have had capacity factors of 3.2% or less during the baseline period, and, in fact, neither unit has had a capacity factor above
10% since 2001.

Finally, both units are currently equipped w ith low-NOx combustion controls, including LNREACH, overfire air (OFA), and flue gas recirc ulation (FGR) controls, and both units already achieve relatively low NOx emission rates (i.e., baseline NOx emission rates for Oswego Units 5 & 6 are 0.22 lb/mmBtu and 0.19 lb/mmBtu, resp ectively). Low baseline NOx emission rates, coupled with the low unit capacity factors, resu lt in baseline annual NOx emissions of only about 240 tpy from each units. The low baseline NOx em ission rates contribute significantly to the high cost-effectiveness of potential retrofit NOx control technologies. Assuming the units continue to operate at low capacity factors, none of the potential NOx control systems, including combustion modifications, would be cost effective.

Table ES-1 Summary of NO x BART Cost Effectiveness Analysis – Oswego Unit 5

Control Technology Controlled Annual Emissions (tpy) Annual Emission Reductions (tpy) Total Annual Costs

($/year) Average Cost Effectiveness

($/ton) SCR 33.0 209.1 $15,288,000 $73,113

LN-REACH (steam atomizer) plus modified OFA and FLGR 132.1 110.0 $4,116,300 $37,421

LN-REACH (steam atomizer) plus modified OFA plus SNCR 143.1 99.0 $2,197,200 $22,194

LN-REACH (pressure atomizer) plus modified OFA and FLGR 143.1 99.0 $3,603,700 $36,401

LN-REACH (pressure atomizer) plus modified OFA plus SNCR 154.1 88.0 $1,684,400 $19,141

LN-REACH (steam atomizer) plus modified OFA 187.1 55.0 $900,500 $16,873

LN-REACH (pressure atomizer) plus modified OFA 198.1 44.0 $384,500 $8,748

Optimize LNB/OFA/FGR with Neural Network Control System 231.1 11.0 $470,900 $42,809

Baseline LNB/OFA/FGR 242.1 -- -- --NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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ES-4 Table ES-2 Summary of NO x BART Cost Effectiveness Analysis – Oswego Unit 6

Control Technology Controlled Annual Emissions (tpy) Annual Emission Reductions (tpy) Total Annual Costs

($/year) Average Cost Effectiveness

($/ton) SCR 33.2 176.9 $15,288,000 $86,422

LN-REACH (steam atomizer) plus modified OFA and FLGR 132.7 77.4 $4,116,300 $53,182

LN-REACH (steam atomizer) plus modified OFA plus SNCR 143.8 66.3 $2,197,200 $33,140

LN-REACH (pressure atomizer) plus modified OFA and FLGR 143.8 66.3 $3,603,700 $54,354

LN-REACH (pressure atomizer) plus modified OFA plus SNCR 154.8 55.3 $1,684,400 $30,459

LN-REACH (steam atomizer) plus modified OFA 177.0 33.1 $900,500 $27,205

LN-REACH (pressure atomizer) plus modified OFA 188.0 22.1 $384,900 $17,416

Optimize LNB/OFA/FGR with Neural Network Control System 199.1 11.0 $470,900 $42,809

Baseline LNB/OFA/FGR 210.1 -- -- --NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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1 1.0 INTRODUCTION

1.1 NRG’s Oswego Power Station

NRG owns and operates the Oswego Power Station (Oswego Station) located on a 93-acre site in Oswego, New York, along the south shore of Lake Onta rio. The station consists of two (2) oil-fired steam electric generating units, four retired un its, and the supporting ancillary equipment and operations needed for operation of the boilers, incl uding an oil storage tank farm and associated rail
facilities.

Oswego Units 5 & 6 are Foster-Wheeler boilers designe d to fire No. 6 fuel oil. The units are rated at 870 MW (gross) each with 6,300,000 lb/hr main steam flow at 2,480 psig pressure and 1,005 o F temperature, and a reheat flow of 5,722,000 lb/hr at 705 psig outlet pressure and 1,005 o F. Each
unit has 32 burners located in the front wall of th e furnace, arranged in four rows of eight. The
burners are fed combustion air from a common windbox. Both units were designed for, and have, operational flue gas recirculation combustion contro l systems. Both units are equipped with an electrostatic precipitator (ESP) for particulate contro l. Unit 6 has the ability to co-fire natural gas, and is capable of generating up to 150 MW utilizing natural gas.

Unit 5 was brought on-line in 1975. Unit 6 was br ought on-line in 1980. Unit 6 is classified as a New Source Performance Standard (NSPS) unit, an d was required, when it commenced operation, to meet the applicable standards in 40 CFR Part 60 Subpart Da.

1.2 New York’s Reasonably Achievable Control Technology (RACT) Rule

The federal Clean Air Act (CAA) requires states with nonattainment areas (i.e., areas that do not meet the federal national ambient air quality sta ndards) to develop a State Implementation Plan (SIP) to “provide for the implementation of all reasonably available control measures as expeditiously as practicable (including such reduc tions in emissions from existing sources in the area as may be obtained through the adoption, at a minimum, of reasonably available control technology) and shall provide for attainment of the national primary ambient air quality standards.” (CAA §172(c)(1)).

EPA’s rules implementing §172(c)(1) of the CAA require states to demonstrate, through a SIP submission, that their RACT requirements addr ess emissions contributing to nonattainment, and effectively work toward achieving compliance with the applicable NAAQS. The New York RACT rules are located in 6 NYCRR 227-2. In general, the RACT rules limit NOx emissions from combustion sources and are designe d to address ozone nonattainment.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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2 1.3 The Regional Haze Rule

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional Haze Regulations and Guidelines for Best Availa ble Retrofit Technology Determinations” (the “Regional Haze Rule” 70 FR 39104). EPA issued the Regional Haze Rule under the authority and requirements of sections 169A and 169B of the Clean Air Act (CAA). Sections 169A and 169B require EPA to address regional haze visibility im pairment in 156 federally-protected parks and wilderness areas (Class I Areas). As mandated by the CAA, the Regional Haze Rule requires certain large stationary sources to install the b est available retrofit technology (BART) to reduce emissions of pollutants that may impact visibility in a Class I Area.

The Regional Haze Rule requires states to develop programs to assure reasonable progress toward meeting the national goal of preventing any future , and remedying any existing, impairment of visibility in Class I Areas. The Regional Haze Rule requires states to submit a plan to implement the regional haze requirements (the Regional Haze SI P). The Regional Haze SIP must provide for a BART analysis of any existing stationary facility that might cause or contribute to impairment of visibility in a Class I Area. To address th e requirements for BART, New York must:

3⁄4 Identify all BART-eligible sources within the State. 3⁄4 Determine whether each BART-eligible source emits any air pollutant which may reasonably be anticipated to cause or contri bute to any impairment of visibility in a Class I Area. BART-eligible sources which ma y reasonably be anticipated to cause or contribute to visibility impairment are classified as BART-applicable sources. 3⁄4 Require each BART-applicable source to identif y, install, operate, and maintain BART controls.

The New York BART regulations are located in 6 NYCRR Part 249.

1.4 Regulatory Applicability Review

1.4.1 RACT Applicability

The New York RACT Rules apply to owners or ope rators of major stationary sources listed in 6 NYCRR 227-2.1, including large and very large boilers. The term “very large boiler” is
defined to include boilers with a maximum heat input capacity greater than 250 mmBtu/hr. Both Units 5 & 6 meet the definition of a very large boiler, and are subject to the RACT requirements in 6 NYCRR 227-2.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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3 1.4.2 BART Applicability Review

BART-eligible sources include those sources that:

(1) have the potential-to-emit 250 tons or mo re of a visibility-impairing air pollutant; (2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and (3) whose operations fall within one or more of the specifically listed source categories in 40 CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 mmBtu/hr heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input).

Oswego Units 5 & 6 are fossil-fuel fired boilers with heat inputs greater than 250 mmBtu/hr. Both units were in existence, as that term is defined in 249.2(d) 1 prior to August 7, 1977, but not in operation prior to August 7, 1962. B ased on baseline emissions data, summarized in Table 2-1, the units have the potential-to-em it more than 250 tons per year of visibility impairing pollutants. Therefore, both units meet the definition of a BART-eligible source.

BART is required for any BART-eligible s ource that emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in a Class I
Area. U.S.EPA has determined that an indivi dual source will be considered to “contribute to visibility impairment” if emissions from the sour ce result in a change in visibility, measured as a change in deciviews ( ∆ -dv), that is greater than or equal to 0.5 dv in a Class I area. However,
New York has determined that all BART-e ligible sources are subject to the BART requirements without source-specific modeling de monstrating that the individual source causes or contributes to visibility impairment. Thus, Oswego Units 5 & 6 are subject to the New York BART determination requirements.

1.5 Regulatory Requirements

1.5.1 RACT Requirements

The RACT control requirements applicable to Oswego Units 5 & 6 are included in 6 NYCRR Section 227-2.4. RACT requirements applicable to a particular emission source may fall into one of two categories: (1) presumptive RACT limits; or (2) case-by-case RACT determinations. Presumptive RACT limits are category-wide requirements based on NOx control capabilities

1 The term “in existence” is defined in subsection 249.2(d) as “the ow ner or operator has obtained all necessary preconstruction approvals or permits required by federal, state, or local air pollution emissions and air quality laws or regulation and either has (1) begun, or caused to begin, a continuous program of physical on-site construction of the facility or (2) entered into binding agreements or contractual obligations, which cannot be canceled or modified without substantial loss to the owner or operator, to undertake a program of construction of the facility to be completed in a reasonable time.”NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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4 that are generally achievable within an emission source category. A case-by-case RACT determination sets a source-specific emission limit based on technical feasibility and economic impacts.

The presumptive RACT limits applicable to Os wego Units 5 & 6 are included in subsection 227-2.4(a):

Prior to July 1, 2012
Gas/Oil Wall-Fired 0.25 lb/mmBtu

On or after July 1, 2012
Gas/Oil Wall-Fired 0.15 lb/mmBtu

In general, compliance with the presumptive RA CT limits must be determined on a 24-hour average basis using a NOx continuous emissions monitoring system (CEMS); however, from
October 1 st to April 30 th , a 30-day rolling average may be used to demonstrate compliance.

For those sources for which the owner or operator demonstrates that the applicable presumptive RACT emission limit is not economically or tec hnically feasible, the owner or operator can request NYDEQ to set a higher source-specific emission limit. 2 Economic or technical feasibility must be demonstrated through a case -by-case RACT analysis that includes, at a minimum, an evaluation of the use of fuel switc hing, the use of a system averaging plan, and implementation of any available control technologies. Each case-by-case determination that establishes source-specific RACT requirements mu st be submitted to the Administrator as a separate SIP revision.

1.5.2 BART Requirements

New York BART regulations are included in 6 NYCRR 249. Section 249.3 of the regulation requires that the owner or operator of a sour ce that is determined to be BART-eligible 3 conduct an analysis to determine the appropriate emission limitation necessary to meet the BART requirements. A determination of BART must be based on an analysis of the best system of continuous emission control technology av ailable and associated emission reductions achievable. The BART analysis must take into consideration: (1) technologies available; (2) costs of compliance; (3) energy and non-air-quality environmental impacts of compliance; (4) any pollution control equipment in use at the sour ce; (5) the remaining useful life of the source;

2 See, 6 NYCRR subsection 227-2.5(c).

3 BART-eligible source are defined in Section 249.X as those units whose emissions of visibility-impairing pollutants result in a visibility impairment equal to or greater than 0.1 deciviews in any Federal Class I Area.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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5 and (6) the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.

Guidelines for making BART determinations ar e included in Appendix Y of 40 CFR Part 51
Guidelines for BART Determinations Unde r the Regional Haze Rule (the “Appendix Y Guidelines”). States are required to use the Appendix Y guidelines to make BART determinations for fossil-fuel-fired generating plants having a total generating capacity in excess of 750 MW. Because the generating capacity of BART-eligible sources at the Oswego Station is greater than 750 MW, from a federal perspective, conformance with the Appendix Y Guidelines is required.

The Appendix Y guidelines for BART determinations identify the following five steps in a case-by-case BART analysis:

Step 1. Identify All Available Retrofit Control Technologies. Step 2. Eliminate Technically Infeasible Options. Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. Step 4. Evaluate Impacts and Document the Results. Step 5. Evaluate Visibility Impacts.

A brief description of each step, and its corresponding New York case-by-case RACT requirement, is provided below.

Step 1. Identify all availabl e retrofit control technologies.

Available retrofit control options are those ai r pollution control technologies with a practical potential for application to the emissions unit a nd the regulated pollutant under evaluation (70 FR 39164 col. 1). Step 1 of the BART determin ation requires applicants to identify potentially applicable retrofit control technologies that represent the full range of demonstrated alternatives. Potentially applicable retrofit c ontrol alternatives can incl ude pollution prevention strategies, the use of add-on controls, or a combination of control strategies. Control technologies required under the New Source Review (NSR) program as Best Available Control Technology (BACT) or Lowest Achievable Em ission Rate (LAER) are available for BART purposes and must be included as potential cont rol alternatives. However, EPA does not consider BART as a requirement to redesign th e source when considering available control
alternatives.

Step 2. Eliminate Technically Infeasible Options.

In step 2 of the BART case-by-case determina tion, the technical feasibility of each potential retrofit technology is evaluated. Control tec hnologies are considered technically feasible ifNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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6 either (1) they have been installed and operated successfully for the type of source under review under similar conditions, or (2) the technology c ould be applied to the source under review. A demonstration of technical infeasibility must be based on physical, chemical and engineering principles, and must show that technical difficulties would preclude the successful use of the control option on the emission unit under consider ation. The economics of an option are not
considered in the determination of technical feasibility/infeasibility. Options that are technically infeasible for the intended application are eliminated from further review.

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies.

Step 3 of the BART determination involves ev aluating the control effectiveness of all the technically feasible control alternatives identifie d in Step 2 for the pollutant and emissions under review. Control effectiveness is generally expressed as the rate at which a pollutant is emitted after the control system has been installed. The most effective control option is the system that achieves the lowest emissions level.

Step 4. Evaluate Impacts and Document the Results.

Step 4 of the BART determination involves an evaluation of potential impacts associated with the technically feasible retrofit technologies. The following evaluations should be conducted for each technically feasible technology:

(1) costs of compliance; (2) energy impacts; and (3) non-air quality environmental impacts.

Costs of Compliance

The economic analysis performed as part of the RACT/BART determination examines the
cost-effectiveness of each contro l technology, on a dollar per ton of pollutant removed basis. Annual emissions using a particular control device are subtracted from baseline emissions to calculate tons of pollutant controlled per year. Annual costs are calculated by adding annual operation and maintenance costs to the annualized capital cost of an option. Cost effectiveness ($/ton) of an option is si mply the annual cost ($/yr) divided by the annual pollution controlled (ton/yr). In addition to the cost effectiveness relative to the base case, the incremental cost-effectiveness to go from one level of control to the next more stringent level of control may also be cal culated to evaluate the cost effectiveness of the more stringent control.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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7 Energy Impact Analysis

The energy requirements of a control technology should be examined to determine whether the use of that technology results in any signi ficant or unusual energy penalties or benefits. Two forms of energy impacts associated with a control option can normally be quantified. First, increases in energy consumption resulting from increased heat rate may be shown as total Btu’s or fuel consumed per year, or as Bt u’s per ton of pollutant controlled. Second, the installation of a particular control opti on may reduce the output and/or reliability of equipment. This reduction would result in loss of revenue from power sales and/or increased fuel consumption due to use of less efficient electrical and steam generation
methods.

Non-Air Quality Environmental Impact Analysis

The primary purpose of the environmental impact analysis is to assess collateral environmental impacts due to control of the re gulated pollutant in question. Environmental impacts may include solid or hazardous wast e generation, discharges of polluted water from a control device, increased water consumption, and land use impacts from waste disposal.

Impact analyses conducted in step 4 should take in to consideration the remaining useful life of the source. For example, the remaining useful life of the source may affect the cost analysis (specifically, the annualized costs of retrofit controls).

Step 5. Evaluate Visibility Impacts.

Step 5 of the BART determination addresses the degree of improvement in visibility that may reasonably be anticipated to result from the u se of the best control technology. CALPUFF modeling, or other appropriate dispersion modeli ng, should be used to determine the visibility improvement expected from the potential BART control technology applied to the source.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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8 2.0 OSWEGO UNIT 5 & 6 RACT/BART DETERMINATION METHODOLOGY

The BART determination process described in th e Appendix Y Guidelines wa s used to identify RACT/BART controls for Oswego Units 5 & 6. Th is report was prepared to support the Oswego Unit 3 RACT/BART determinations, and includes an evaluation of technologies available to control NOx, PM and SO 2 emissions from the units. This report is arranged to include the information and evaluations required by Steps 1 thorough 4 of the Appendix Y BART Evaluation Guidelines.

Baseline operating parameters and emissions for Oswego Units 5 & 6 are summarized in Table 2-1. Baseline emissions from Oswego Units 5 & 6 are based on an evaluation of actual emissions from the units during the baseline years of 2007 – 2009. Baseline NOx emissions for both units were calculated using actual average NOx mass emissions (tons) and actual average heat input to each boiler (boiler) for the three year baseline period. 4 The operating parameters and emissions
summarized in Table 2-1 form th e basis for the Oswego PM and SO 2 BART determinations, and
the NOx RACT/BART determination.

Section V of the Appendix Y guidelines specify that BART emission limitations for EGUs should be based on 30-day rolling averages; therefore, this engineering evaluation is based upon the 30-day rolling average emission rates achievable with each technically feasible retrofit technology. The RACT/BART cost effectiveness evaluations ($/ton, Step 4) are based on a comparison of total
annual costs and annual emission reductions. Annu al emissions associated with each retrofit technology were calculated using the 30-day rolling average emission rate and a representative unit capacity factor.

4 This approach is consistent with the approach used by U.S.EPA to calculate control technology costeffectiveness in the Four Corners and Navajo Power Pl ants’ BART determinations (see, 74 FR 44321, August 28, 2009).NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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9 Table 2-1 Unit Operating Parameters for the Oswego Units 5 & 6 BART Evaluations

Parameter Oswego Unit 5 Oswego Unit 6
Unit Configuration oil-fired boiler oil-fired boiler Firing Configuration wall-fired wall-fired Unit Output (gross) 870 MW 870 MW Boiler Heat Rate (Btu/kW-hr) 9,233 9,297 Full Load Heat Input (mmBtu/hr) 8,033 mmBtu/hr 8,088 mmBtu/hr Primary Fuel fuel oil fuel oil Existing NOx Controls LNB/OFA/FGR LNB/OFA/FGR Existing SO 2 Controls Fuel Sulfur Fuel Sulfur Existing PM 10 Controls ESP ESP Baseline Annual Heat Input 2,201,269 mmBtu 1,155,655

Baseline Emissions Baseline Actual Emissions Baseline Actual Emissions

Pollutant Averaging Time lb/mmBtu tpy lb/mmBtu tpu NOx annual average 0.22 243 0.19 107
PM (filterable) annual average 0.022 23.8 0.022 12.5NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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10 3.0 NITROGEN OXIDES (N Ox) CONTROL EVALUATION

New York regulations require that any case-by-case RACT evaluation include, at a minimum, the use of fuel switching, the use of a system averaging plan, and implementation of any available control technologies. This report does not include an evaluation of the feasibility of fuel switching or system averaging, but focuses on the implementa tion of available control technologies.

The formation of NOx is determined by the in teraction of chemical and physical processes occurring primarily within the flame zone of the boiler. There are two principal forms of NOx designated as “fuel” NOx and “thermal” NOx. Fuel NOx is formed by the oxidation of nitrogen in
the fuel. Thermal NOx formation is the result of oxidation of atmospheric nitrogen contained in the inlet gas in the high-temperature, post-flam e region of the combustion zone.

Fuel oil properties will affect the formation of fuel NOx. For nitrogen containi ng fuels, such as fuel oil, the oxidation of nitrogen that is organically bound to the fuel molecule can become the primary
source of total NOx emissions. As the fuel burns , the fuel nitrogen disassociates to form unstable nitrogen radicals. The nitrogen radicals will eith er be oxidized to form NOx, or bond with another nitrogen radical to form atmospheric nitrogen (N 2 ).

The major factors influencing NOx formation are temperature, the concentration of combustion gases (primarily nitrogen and oxygen) in the inle t air, and residence time within the combustion zone. Experimental measurements of thermal NOx formation have shown that NOx formation is exponentially dependent on temperat ure, and is proportional to n itrogen and oxygen concentrations
in the flame. The formation of fuel bound NOx can also be reduced by delaying (or staging) mixing of stoichiometric air. Reducing the oxyg en available to the nitrogen radicals favors the
formation of N 2 . Advanced burner designs can regulate the distribution and mixing of the fuel and air to reduce flame temperatures and residence ti mes at peak temperatures to reduce thermal NOx
formation.

NOx emissions from oil-fired boilers can be c ontrolled by adjusting the combustion process and reducing NOx formation in the boiler, and/or in stalling post-combustion NOx control systems.

3.1 Step 1: Identify Potentially Feasible NOx Control Options

Potentially available control optio ns were identified based on a comprehensive review of available information. NOx control technologies with poten tial application to Oswego Units 5 & 6 are listed
in Table 3-1.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

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11 Table 3-1 List of Potential NOx Control Options

Control Technology

Combustion Controls
Low NOx Burners (LNB), Overfire Air (OFA), and Flue Gas Recirculation (FGR) (optimize existing NOx combustion controls)

Low NOx Reduced Emissions and Advanced Combustion Hardware (LN-REACH) and Modified OFA Controls
Neural Network Combustion Control Systems
Gas Reburn Systems and Advanced Gas Reburn
Fuel Lean Gas Reburn (FLGR) and Amine Enhanced FLGR (AEFLGR)

Post-Combustion Controls
Selective Noncatalytic Reduction (SNCR)
Selective Catalytic Reduction (SCR)
Innovative Control Technologies
Rotating Overfire Air (ROFA)
ROFA plus SNCR (Rotamix)
NOxStar Control System
Powerspan ECO Technology

3.2 Step 2: Technical Feasibility of Potential Control Options

Control technologies can be divided into two ge neral categories: combustion controls and postcombustion controls. Combustion controls reduce the amount of NOx that is generated in the
boiler. Post-combustion controls remove NOx from the boiler exhaust gas. The technical feasibility of each potentially available NOx control strategy, with respect to Oswego Units 5 & 6,
is evaluated below.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

12 3.2.1 Combustion Controls

The rate of NOx formation in the combustion zone is a function of free oxygen, peak flame temperature and residence time. Combustion tec hniques designed to minimize the formation of NOx will minimize one or more of these variables. Currently, both Oswego Units 5 & 6 are equipped with low-NOx burners (LNB), overfire air (OFA), and flue gas recirculation (FGR) control systems. A description of the existi ng combustion controls is provided below.

3.2.1.1 Oswego Units 5 & 6 – Existing Combustion Controls

Oswego Units 5 & 6 are Foster-Wheeler boilers d esigned to fire No. 6 fuel oil. Each unit
has 32 burners located in the front wall of the furnace, arranged in four rows of eight. The burners are fed combustion air from a common windbox. Both units are equipped with low NOx burners (LNB), flue gas recirculation (FGR), and overfire air (OFA) ports.

Low NOx burners limit NOx formation by controlling both the stoichiometric and temperature profiles of the combustion flame in each burner flame envelope. Control is achieved with design features that regulate the aerodynamic distribution and mixing of the fuel and air, yielding reduced oxygen (O 2 ) in the primary combustion zone, reduced flame temperature, and reduced residence time at peak combustion temperatures. The combination of these techniques produces lower NOx emissions during the combustion process; however, the mechanisms used to re duce NOx formation (e.g., cooler flame and
reduced O 2 availability) also tend to increase the formation and emission of carbon monoxide (CO).

In the overfire air (OFA) process, the injection of air into the firing ch amber is staged into zones, in which approximately 5% to 20% of the total combustion air is diverted from the burners and injected through ports located above the top burner level. Staging the combustion air reduces NOx formation by two mechanisms. First, staged combustion results in a cooler flame, and second the staged combustion results in less oxygen reacting
with fuel molecules.

The degree of staging (i.e., the percent of combustion air diverted from the burners) is limited by boiler-specific operational issues. As the amount of OFA is increased, the stoichiometry in the burner zone decreases, resulting in substoichiometric combustion in the primary burner zone (primary furnace S < 1.0). OFA systems are designed to provide
the additional O 2 needed to complete combustion; however, a point will be reached at which CO emissions become unacceptably high. The point at which this occurs is boilerspecific, and depends on the system’s ability to balance flows between the individualNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

13 burners. As the amount of OFA approaches 10 – 15%, the probability for individual burners operating under substoic hiometric conditions increases, potentially forming pockets of high CO emissions and unburned carbon.

Flue gas recirculation (FGR) controls NOx by recycling a portion of the flue gas back into the primary combustion zone. The recycled ai r lowers NOx emissions by two mechanisms: (1) the recycled gas, consisting of products that are inert during combustion, lowers the combustion temperatures; and (2) the recycled gas will reduce the oxygen content in the primary flame zone. The amount of recircula tion is based on flame stability. In general, FGR is more effective on natural gas-fired boilers because it reduces the formation of thermal NOx, which represents almost 100% of the NOx produced in a natural gas-fired boiler. In oil-fired boilers a majority of the NOx formed can be from fuel bound nitrogen;thus, the use of FGR will have a somewhat lower impact on overall NOx formation in oilfired applications.

Oswego Units 5 & 6 are currently equipped with Low-NOx Reduced Emissions and Advanced Combustion Hardware (LN-REACH) high-pressure return nozzle systems. Each unit has two levels of eight OFA ports (total of 16 ports) directly in line with each burner
column.

Application of LN-REACH typically involves the custom design of retrofit oil atomizers and flame stabilizers. LN-REACH oil atomizers can be designed as mechanically atomized burners or steam-atomized systems. In either case, the atomizers are designed to provide more effective oil spray quality to promot e fuel evaporation, as well as radial and circumferential staging of the fuel within the combustion zone. Flame stabilization and control of fuel and air mixing is required to produce the proper entrainment and swirl of combustion air at the discharge plane of the bur ner to match the oil spray of the atomizer. Staging within the combustion zone reduces the formation of both thermal and fuel NOx.

The existing combustion control systems on Oswego Units 5 & 6 effectively reduce NOx emissions by reducing the delaying the introduc tion of stoichiometric air and reducing the primary flame temperatures. Boiler furnace stoi chiometry levels on Unit 5 were calculated
to be 0.87 to 0.91 for summer and winter operation, respectively, while boiler furnace stoichiometry levels calculated for unit 6 were somewhat lower at 0.81 to 0.84 for summer and winter, respectively. Boiler furnace stoi chiometries were calculated based on firing No. 6 fuel oil and boiler operating O 2 level at full load. These boiler stoichiometries limit the conversion of fuel bound nitrogen to NOx by limiting the availability of O 2 .NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

14 The existing OFA system is designed to pr ovide the stoichiometric air necessary for complete combustion. OFA port velocities associated with the existing systems were calculated to be approximately 75 ft/second based on an OFA flow of 20%. This velocity is approximately 2-times the furnace flue gas flow rates calculated for both Oswego units 5 & 6, and is below the recommended design OFA velocity of 5-times the furnace flue gas flow rate. Higher OFA velocities are required for to optimize jet penetration in the upper furnace and promote complete fuel burnout. Th us, modifications to the existing OFA ports may provide for better jet penetration a nd flue gas mixing in the upper furnace.

During the baseline years of 2007 thru 2009, Oswego Units 5 & 6 achieved average
controlled NOx emission rates of 0.22 and 0.19 lb/mmBtu (actual average), respectively.
Unit 6 is able to achieve lower baseline NOx emissions because NRG is able to operate
Unit 6 at somewhat lower boiler furnace stoich iometries. Annual emissions from Units 5 & 6 during the baseline period, averaged 243 and 107 tpy, respectively. Both units currently meet the applicable NOx RACT emission limit of 0.25 lb/mmBtu; however, both units are above the proposed July 1, 2012 limit of 0.15 lb/mmBtu.

3.2.1.2 Process Optimization Modeling S ystem or Neural Network Control

As discussed above, NOx formation in an oil -fired boiler is a function of a multitude of operating variables. NOx formation will fluc tuate based on furnace cleanliness, air-to-fuel ratios, mixing, OFA jet penetration, and combustion air staging. It is extremely difficult to continually optimize the combustion and thermal efficiencies of an oil-fired boiler as operating changes lead to deviations from optim al combustion and can result in short-term
increases in emissions.

Neural network based combustion optimiza tion systems have been developed to continually respond to changes in boiler operati ng variables. Neural control systems are capable of analyzing data from multiple sensors and, once trained, are able to recognize sub-optimal combustion conditions. Neural networks are designed to “learn” from observations made from operating data, and algorithms are used to determine optimal solutions based on user-defined objectives.

Neural network combustion optimizers have been installed on a number of utility boilers in the U.S., including T-fired boilers with LNB/close-couple OFA; face-fired boilers with LNB/OFA, cyclone boilers, and opposed-fired boilers with LNB/OFA. Many of these systems have demonstrated the capability to operate greater than 90% of the time in supervisory modes, and have beco me a boiler operational tool.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

15 Neural network control systems interface dir ectly with the unit’s DCS control system to provide continuous combustion tuning. Neur al network systems can tune up to 90 manipulative variables (MV) simultaneously, with the goal of continuously optimizing selected control variables. The systems a llow boiler operators to enable or disable individual control loops while keeping the total neural network operational, adding operational flexibility to the system.

Neural network control systems and predic tive dynamic controllers are a technically feasible and commercially available NOx control strategy. By installing a neural net-based control system, optimal combustion conditions can more readily be maintained over long periods of time, and the system should respond more rapidly to changing operating
variables to minimize short-term emission excursions.

Neural network based control systems are designed to provide continuous response to transient operating conditions. When used in conjunction with the existing LNB/OFA/FGR control systems, neural network control s hould reduce short-term NOx excursions and
reduce the maximum 24-hour NOx emission rate. Installation of a neural network control system would be expected to reduce the 30-day average NOx emission rate from each boiler by approximately 5%. Assuming a 5% reduction in the 30-day average emission rate, installing a neural network based c ontrol system would achieve the following
controlled NOx emission rates:

Controlled NOx Emission Rate (lb/mmBtu 30-day average) Control Option
Unit 5 Unit 6 Existing Combustion Controls plus Neural Network 0.21 0.18

3.2.1.3 Combustion Optimization and Modified Overfire Air

As discussed in section 3.2.1.1, Oswego Units 5 & 6 are currently equipped with LNREACH high-pressure return nozzles and OFA. However, as currently designed, OFA jet velocities using one level of OFA with 20% air flow, are approximately two-times the average boiler flue gas flow rate (signifi cantly below the recommended design level of 5- times the furnace flue gas flow rate). In add ition, the average reside nce time in the furnace for both units, is 0.35 seconds from the centerline of the top row of burners to the centerline of the upper level of OFA ports, and 0.60 seconds from the centerline of the top row ofNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

16 burners to the start of the convective sections, limiting the total time under
substoichiometric conditions.

One approach to reduce boiler NOx emissions is to take the upper burner level out of service (8 burners) and replace the lower three burner levels (24 burne rs) with oversized high-pressure return LN-REACH burners designe d for maximum full load oil flow rates at the same operating pressure. This configuration would increase the residence time in the units by 0.27 to 0.63 seconds from the highest burner level centerline to the top level of OFA ports, increasing the total time under subs toichiometric conditions and allowing for additional combustion staging. Finally, the existing FGR system could be used for both NOx control and superheat/reheat (SH/RH) temp erature control throughout the boiler load

range.

As is the case for all low-NOx operations, it is very important to have balanced local air-tofuel (A/F) ratios to achieve minimum boiler O 2 levels without generating high CO levels. Modifications to the existing OFA ports to increase the jet velocities from two-times the flue gas velocity to five-times the flue g as velocity would provide for better mixing and burnout in the upper furnace, keeping CO to acceptable levels.

The LN-REACH system could be designed with mechanically-atomized burners or steamatomized system. Converting from high-pressure return mechanical atomizers to steam atomized burners results in smaller droplet size distribution, reducing the formation of carbonaceous particulates and CO formation. The steam atomizer concept involves fuelrich and fuel-lean sections in the near-zone of the burner, which reduces overall peak flame temperatures as well as changing the near-zone mixing characteristics (i.e., flame shape). Steam required for the steam atomizing system would be taken from the boiler system, and it is assumed that the existing auxiliary bo iler would provide steam needed during unit
startup.

Although Oswego Units 5 & 6 are currently equipped with LNB and OFA combustion control systems, reconfiguring the firing sy stems and replacing the existing burners with oversized high-pressure return LN-REACH technology or steam atomized LN-REACH system, and modifying the exiting OFA system to provide better jet penetration would be technically feasible and commercially available retrofit NOx control strategies. These modifications would provi de better mixing and increased residence time at
substoichiometric conditions on both units. The combination of oversized LN-REACH and modified OFA systems should achieve controlled NOx emission rates on both units belowNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

17 the baseline. Based on engineering judgment, it is anticipated that these modifications could achieve the following controlled NOx emission rates:

Controlled NOx Emission Rate

(lb/mmBtu 30-day average) Control Option
Unit 5 Unit 6 LN-REACH (pressure atomizers) + modified OFA 0.18 0.17

LN-REACH (steam atomizers) + modified OFA 0.17 0.16

3.2.1.4 Gas Co-Firing (Unit 6)

NOx emissions from an oil-fired boiler can be redu ced by co-firing the oil with natural gas. Natural gas is a low nitrogen fuel, thus, co-fi ring reduces the quantity of nitrogen available to form fuel NOx. In addition, FGR (which reduces NOx by recycling a portion of the flue gas back into the primary combustion zone) more effectively reduces the formation of thermal NOx, which represents almost 100% of the NOx produced from natural gas
combustion.

Oswego Unit 6 currently has the ability to co-fi re natural gas; however, based on natural gas availability at the station, natural gas co -firing would be limited to approximately 1,500 mmBtu/hr, or about 18% of the full load heat input to the boiler. Unit 6 does not currently co-fire natural gas for the following reasons. First, because Unit 6 operates in a cycling mode and does not provide baseload power, th e quantity of natural gas consumed would vary significantly over time. To secure the gas needed to co-fire Unit 6, NRG would be required to secure a specific quantity of gas, wh ether the gas is actually consumed or not, and the facility cannot guarantee that it will c onsume a specific quantity of natural gas. Second, because of physical limits associated with the boiler design, co-firing natural gas above a total boiler generating capacity of a pproximately 400 MW is not possible due to the tightness of the primary furnace and the available residence time.

Natural gas and oil flames do not have the sa me luminosity, and co-firing natural gas will increase the furnace exit gas temperature (FEGT) of the boiler. FEGT has a direct affect on the superheat (SH) and reheat (RH) steam temperatures, which are limited by boiler metallurgy. SH/RH temperatures cannot exceed specific maximum allowable limits, limiting FEGT and the quantity of natural gas that can be fired in a boiler. In order to cofire natural gas above the 300 to 400 MW lo ad range would require major boiler pressureNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

18 part modifications to the SH/RH sections of the boiler. CFD modeling would be required to see if these major boiler modifications are technically feasible, and the SH/RH metallurgy would need to be evaluated for natural gas co-firing.

Natural gas co-firing is not a technically feasible NOx control option on Oswego Unit 6 due
to both technical and economic issues. As di scussed above, co-firing at a boiler load above approximately 300 to 400 MW is not technica lly feasible due to boiler tightness and FEGT design limitations. Co-firing natural gas above this level would require significant modifications of the pressure parts of the SH/R H sections of the boiler. At lower loads, natural gas co-firing would require NRG to secu re a specific quantity of natural gas from the supplier. Securing an adequate supply of natural gas would require the facility to subscribe to a specific quantity of natural g as (to ensure availability to all natural gas users). Because Unit 6 is operated as a load fo llowing unit, and has a low capacity factor, itwould not be practical to subscribe to a given quantity of natural gas. Furthermore, cofiring at low loads does not address the boiler tightness issues, and would effectively limit
maximum boiler load.

Taking into consideration Unit 6 flue gas flow rates, boiler dimensions, residence times, and natural gas availability it was determined that natural gas co-firing would not be a feasible NOx control option.

Controlled NOx Emission Rate (lb/mmBtu 30-day average) Control Option
Unit 5 Unit 6 Gas Co-Firing (150 MW) Unit 6 Not Available Not Feasible
Gas Co-Firing (>150 MW) Unit 6 Not Available Not Available
Gas Co-Firing Both Units Not Available Not Available

3.2.1.5 Gas Reburn

Gas reburn technology injects a secondary fuel into the furnace above the burner zone. The technology involves combustion in three dis tinct zones within the boiler: (1) a primary combustion zone where the primary fuel is fired using conventional burners; (2) a reburn zone where secondary fuel, typically natural g as, is introduced into the boiler; and (2) an
overfire air burnout zone.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

19 In the primary zone, oil would be fired u tilizing low-NOx burners (described in section 3.2.1.3) at a rate corresponding to approximately 80-90% of the total heat input. Natural gas reburn fuel would be injected above the primary combustion zone under fuel-rich conditions at a rate corresponding to approxima tely 10-20% of the total heat input. The fuel-rich reburn zone creates a reducing region within the boiler where the natural gas, principally methane (CH 4 ), breaks down to produce hydrocarbon fragments (CH and CH 2 ). The hydrocarbon fragments react with NOx produced in the primary combustion zone to reduce NOx to atmospheric nitrogen (N 2 ). Gases exiting the reburn zone will contain considerable CO and unburned hydrocarbons; th erefore, additional overfire air (referred to as completion air) is introduced above the reburn z one to complete the combustion process.

Critical design parameters that affect the feasibility and performance of a gas reburn retrofit system include: (1) primary NOx concentration; (2) reburn zone temperature, residence time and stoichiometry: (3) overfire air burnout zone temperature and residence time; and (4) mixing of the reburn fuel and overfire air with the bulk flue gas.

In reburning, the main combustion zone operat es at a relatively low oxygen stoichiometry of 0.9 to 1.1, and receives a bulk of the fuel input (80 to 90% of total heat input). The balance of the heat input is injected afte r the main combustion zone through reburning injections. The stoichiometry in the reburn zone should be within a range of 0.85 to 0.95. Temperatures in the reburn zone must be above 1,800 o F to provide an environment for the decomposition of the reburn fuel. These substoic hiometric conditions add risk to the boiler operation due to high-temperature vanadium corrosion attack and H 2 S-accelerated tube corrosion that will occur under this reducing environment. These conditions can result in more forced boiler outages, boiler downtime, and increased O&M costs.

Residence time in the furnace between the rebur n fuel injection ports and the OFA ports is also an important design criteria. Typically, a residence time in the furnace between 0.5
and 1.0 second is needed to allow for NOx reducti on reactions to occur. There must also be sufficient residence time above the OFA ports to allow for complete combustion and
minimize CO emissions. The residence time cal culated for both units from the top row of burners to the start of the convective passag es are in the range of 0.6 seconds. This residence time is indicative of a tight furn ace, and would reduce the effectiveness of the reburn control option. Therefore, to be effective, the gas reburn technology would need to incorporate combustion modifications discussed in section 3.2.1.3. Those modifications would: (1) increase the furnace residence time between the top burner level and the OFA ports; (2) increase OFA jet velocities and penetration/mixing in the upper furnace toNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

20 complete burnout of natural gas fuel in the upper furnace; and (3) reduce CO levels exiting
the furnace.

However, the same natural gas supply issu es, and FEGT issues discussed in subsection 3.2.1.4 would apply to the gas reburn option. To secure the natural needed for gas reburn, NRG would be required to subscribe to a specifi c quantity of fuel. Because Unit 6 is not a baseload unit, it would be impractical to subscrib e to a specific quantity of gas. In addition, natural gas reburn above a total boiler gene rating capacity of 300 to 400 MW is not possible due to the tightness of the primary fu rnace, residence time, and boiler metallurgy. To install natural gas reburn to the 18% heat input required for this technology to achieve effective NOx control, major boiler pressure pa rt modifications to the SH/RH sections of the boiler would be required, and CFD mode ling would be required to see if these major
boiler modifications are even feasible.

Taking into consideration Unit 6 flue gas flow rates, boiler dimensions, residence times, tightness of the primary furnace, and natural g as availability, natural gas reburn is not a technically feasible option for Unit #6.

Controlled NOx Emission Rate (lb/mmBtu 30-day average) Control Option
Unit 5 Unit 6 LN-REACH (pressure atomizers) + modified OFA and Gas Reburn Not Available Not Feasible

LN-REACH (steam atomizers) + modified OFA and Gas Reburn Not Available Not Feasible

3.2.1.6 Fuel Lean Gas Reburn (FLGR)

Like other gas reburn systems described in s ubsection 3.2.1.5, the fuel lean gas reburn (FLGRTM) process injects natural gas above the main combustion zone of the furnace to
reduce NOx to N 2 . FLGR is designed to achieve comp aratively moderate NOx reductions using much lower gas input than conventional reburn systems. Because less natural gas is used with the FLGR system, the FEGT issues di scussed in subsection 3.2.1.4 become less critical, and the technology may be technically feasible without major modifications to the boiler pressure parts.

Unlike more conventional gas reburn designs, FLGR is designed to avoid fuel-rich zones within the gas reburn section and maintain overa ll fuel-lean conditions. Maintaining a fuellean environment throughout the furnace eliminates the need for downstream overfire air toNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

21 complete combustion (i.e., burnout zone), and prevents formation of reducing conditions in
the boiler.

FLGR is an in-furnace NOx reduction technology, where natural gas (or another secondary fuel) acts as a reducing agent to convert NOx to N 2 . The natural gas injected for NOx reduction will replace approximately 3% to 7% of the total heat input to the boiler (compared to 10 to 20% with mo re conventional reburn). Seconda ry fuel is injected within a temperature window of 2,000 to approximately 2,400 o F, which supports the chemical
reactions that reduce NOx to N 2 . The temperature at the injection location should be as low as possible consistent with the requirement of th e reburn fuel ignition and burnout. Lower gas injection temperatures with FLGR allow lower NOx levels without making the entire furnace cross-section substoichiometric, which can eliminate the need for OFA above the injection point.

To effectively reduce NOx emissions, the natural gas must be injected in such as way as to achieve complete mixing and adequate residen ce times in the upper boiler, while creating only localized substoichiometric conditions. To achieve sufficient mixing, natural gas is injected into the upper furnace using multiple hi gh-velocity turbulent gas injection jets. Generally, detailed computational fluid dynami cs (CFD) modeling of the boiler is required to optimize the gas injection system.

The most significant operational parameters that affect the performance of a FLGR system are: (1) reburn zone residence time and te mperature; (2) CO levels; and (3) fuel/O 2 stoichiometry. The limiting factor for the control system is complete reburn gas
combustion without localized substoichiomet ric conditions or excess CO emissions. The amount of natural gas that can be injected into the upper furnace to reduce NOx will be limited by residence time. As greater amount s of natural gas are injected in the upper furnace, conditions will be reached that inhib it both NOx reduction and complete burnout.

The reburn fuel injection level in the uppe r furnace must be installed where sufficient residence time exists for the fuel to comple te its burnout process. When natural gas is injected into the upper furnace, it can cons ume oxygen required for the primary fuel burnout process. This will result in hi gher CO emissions and increased unburned carbon (UBC) due to incomplete No. 6 fuel oil burno ut. Therefore, installation of FLGM control systems on the Oswego boilers would be c oupled with the upgraded LN-REACH and modified OFA controlled systems described in section 3.2.1.2.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

22 A boiler with an LNB/OFA system will have substoichiometric conditions in the primary furnace (0.85 to 0.95). The introduction of the OFA with good jet penetration will complete the burnout of the primary combustion zone resulting in stoichiometries at the entrance to reburn zone in the range of 1.05-1. 15. Sufficient residence time in the upper furnace must be available in order to take advantage of the NO X reduction capabilities of both technologies. CFD modeling of the primary burnout process and the natural gas reburn process, as well as a parametric testing program, is often needed to determine the minimum levels of excess air in the primary furnace combustion zone required to sustain safe and flexible boiler operation. CFD and LIM (or other turbulent mixing) modeling can be combined to formulate the reburn gas injec tion design (size, location, number, velocity, etc.).

As with the other natural gas options, FLGR may not be possible above a total boiler generating capacity of 300 to 400 MW due to the tightness of the primary furnace, residence time, and FEGT issues. However, unlike more conventional reburn systems that replace 10 to 20% of total heat input to the boiler with natural gas, FLGR replaces only 3% to approximately 7% of the heat input with natural gas. Thus, the FEGT issues discussed in subsection 3.2.1.4 become less critical, and th e technology may be feasible without major modifications to the boiler pressure parts.

Another advantage of the FLGR control option is that the total amount of natural gas currently available at the site would be suffi cient to install this process on both boilers. However, the natural gas subscription issues di scussed in subsection 3.2.1.4 still apply, and the natural gas needed to effectively implemen t the FLGR system may be subject to limited seasonal availability.

Based on an engineering review of Oswego Units 5 & 6, including flue gas flow rates and boiler dimensions, it was determined that FLGR is a technically feasible retrofit NOx control technology. Although the absolute ma ximum natural gas heat input to the existing boiler configurations cannot be determined without CFD modeling, based on engineering
calculations the total FLGR zone within th e upper furnace (above the OFA ports) has a residence time of only 0.3 seconds, which lim its the maximum heat input from the reburn fuel to 4% of the total boiler heat input. The 4% heat input from natural gas should also be acceptable at full boiler loads without the need for boiler pressure part modifications, although CFD modeling would be needed to conf irm this conclusion. The relatively short
residence time calculated for both units from th e top row of burners to the start of the convective passages will limit the effectiveness of the FLGR control system. Unburned fuel leaving the reburn zone will be fired to completion in the burnout zone.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

23 Taking into consideration Unit 5 & 6 flue g as flow rates, boiler dimensions, residence times, and tightness of the primary furnace, and assuming 96% heat input from fuel oil and 4% natural gas as reburn fuel, coupled with using oversized LN-REACH atomizers and modified OFA ports (higher jet velocities), it was determined that FLGR could achieve the following controlled NOx emission rates:

Controlled NOx Emission Rate

(lb/mmBtu 30-day average) Control Option
Unit 5 Unit 6 LN-REACH (pressure atomizers) + modified OFA and FLGR 0.13 0.13

LN-REACH (steam atomizers) + modified OFA and SNCR 0.12 0.12

3.2.1.7 Combustion Control Conclusions

Several combustion control systems are considered technically feasible and commercially available retrofit NOx control technologies fo r Oswego Units 5 & 6. The control systems include: (1) optimizing the existing combustion controls with a Neural Network control system; (2) upgrading and reconfiguring the ex isting combustion controls with LN-REACH atomizers (mechanical or steam) and modifying the existing OFA ports; and (3) combustion controls plus FLGR on both units.

3.2.2 Post-Combustion Controls

Post-combustion NOx control systems with potential application to Oswego Units 5 & 6 are
discussed below.

3.2.2.1 Selective Non-Catalytic Reduction

Selective non-catalytic reduction (SNCR) involves the direct injection of ammonia (NH 3 ) or urea (CO(NH 2 ) 2 ) at high flue gas temperatures of approximately 1,750 ± 50 oF. The ammonia or urea reacts with NOx in the flue gas to produce N 2 and water as shown in the equations below:

(NH 2 ) 2 CO + 2NO + 1⁄2O 2 → 2H 2 O + CO 2 + 2N 2 2NH 3 + 2NO + 1⁄2O 2 → 2N 2 + 3H 2 ONRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

24 Flue gas temperature at the point of reagen t injection will greatly affect NOx removal efficiencies and the quantity of NH 3 or urea that will pass through the SNCR unreacted (referred to as NH 3 slip). In general, SNCR reactions are effective in the range of 1,750 ±
50 o F. At temperatures below the desired operating range, the NOx reduction reactions
diminish and unreacted NH 3 emissions increase. Above the desired temperature range,

NH 3 is oxidized to NOx resulting in low NOx reduction efficiencies and potentially
increased NOx emissions.

Mixing of the reactant and flue gas within the r eaction zone is also an important factor to SNCR performance. In large boilers, the physical distance over which reagent must be dispersed increases, and the surface area-to-vol ume ratio of the convective pass decreases. Both of these factors make it difficult to achieve good mixing of reagent and flue gas within the required temperature window. In addition to temperature and mixing, several other factors influence the performance of an SNCR system, including residence time, reagent-to-NOx ratio, and fuel sulfur content.

SNCR control systems have been installed as retrofit NOx control systems on small and medium sized (i.e., less than approximately 300 MW) boilers. Because of design and operating limitations, SNCR has not been used ex tensively on larger boilers. As the boiler size increases, it becomes physically more di fficult to achieve adequate reagent mixing and residence time within the required flue gas temperature window to achieve effective NOx
reduction.

The physical size of Oswego Units 5 & 6 will present significant design challenges tolocate and install ammonia/urea injection points capable of achieving adequate reagentNOx contact. Higher reagent injection rates could provide additional reagent-NOx contact, but would also result in higher levels of reag ent slip (i.e., unreacted ammonia or urea in the flue gas). However, injecting excess reactant is not a viable NOx control option. Excess reagent in the flue gas can react with sulfur compounds in the flue gas to form ammonium bisulfate and lead to significant plugging of downstream equipment. To be feasible, the SNCR control system would have to be designe d with a maximum slip of approximately 5

ppm.

Because Oswego Units 5 & 6 tend to operate over a wide operational load window, the area of optimal reaction temperature will vary acr oss the load range. Control of injection systems during transient operations is difficu lt as temperatures will vary within the furnace, and maintaining injection at the optimum te mperature becomes difficult. To address theseNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

25 load changes, the SNCR control systems would ha ve to include multiple levels of injection nozzles and a sophisticated control schem e to ensure minimal ammonia slip.

Finally, SNCR NOx reduction efficiency is redu ced substantially when CO levels go above approximately 200 ppmv. As discussed in section 3.2.1.2, CO levels from the boilers would be addressed by modifying the existing OFA systems to provide better jet penetration, mixing, and increased residence ti me. Therefore, to be effective, SNCR would only be installed on Oswego Unit 5 or 6 in c onjunction with the combustion modifications
described in section 3.2.1.2.

Based on an engineering evaluation of th e Oswego boilers, SNCR is considered a technically feasible and commercially availabl e retrofit NOx control technology. However, as described above, there are several techni cal difficulties associated with applying SNCR to large boilers that will limit its effectiven ess, including the ability to achieve adequate reagent mixing and reagent-NOx contact with in the required temperature window while maintaining slip within acceptable limits. B ased on NOx removal efficiencies achieved in practice on smaller boilers equipped with SNCR, the physical size of Oswego Units 5 & 6, information available from control technology vendors, and engineering judgment, it is concluded that SNCR coupled with the LN-R EACH and modified OFA control systems on both units could achieve the following controlled emission rates:

Controlled NOx Emission Rate

(lb/mmBtu 30-day average) Control Option
Unit 5 Unit 6 LN-REACH (pressure atomizers) + modified OFA and SNCR 0.14 0.14

LN-REACH (steam atomizers) + modified OFA and SNCR 0.13 0.13

3.2.2.2 Selective Catalytic Reduction

Selective catalytic reduction (SCR) involves inj ecting ammonia into boiler flue gas in the presence of a catalyst to reduce NOx to N 2 and water. Anhydrous ammonia injection systems may be used, or ammonia may be generated on-site from a urea feedstock. The
overall SCR reactions are:

4NH 3 + 4NO + O 2 → 4N 2 + 6H 2 O 8NH 3 + 4NO 2 + 2O 2 → 6N 2 + 12H 2 ONRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

26 The performance of an SCR system is influen ced by several factors including flue gas temperature, SCR inlet NOx level, the catalys t surface area, volume and age of the catalyst, and the amount of ammonia slip that is acceptable.

The optimal temperature range depends on the type of catalyst used, but is typically
between 560 o F and 750 o F to maximize NOx reduction efficiency and minimize ammonium sulfate formation. This temperature range typically occurs between the economizer and air heater on a large utility boile r. Below this range, ammonium sulfate is formed resulting in catalyst deactivation. A bove the optimum temperature, the catalyst will sinter and thus deactivate rapidly.

Incorporating an SCR control system into an existing boiler can represent significant retrofit challenges. SCR control systems ar e large and require adequate space for the catalyst. The SCR reactor must be located in an area where flue gas temperatures are between approximately 560 o F and 750 o F. On Oswego Units 5 & 6 this area occurs
between the economizer outlet and air heater in let, upstream of the Unit’s ESP. As noted during a walk down of Oswego Units 5 & 6, access to the economizer outlet needed to install duct work to and from SCR is extremely tight, and could make locating the SCR in this area technically infeasible. Detailed engin eering would be required to determine if the space is available for duct work installation.

Experience also shows that SCR control on an oil-fired boiler can result in significant balance-of-plant impacts. Potential balance- of-plant impacts that must be taken into consideration include the potential for increas ed sulfuric acid mist (SAM) and ammonium
bisulfate formation.

Vanadium in the fuel oil ash will cause SO 2 in the flue gas to more readily convert to SO 3 , which can react with water to form sulfuric acid mist and increase emissions of fine particulates. It is likely that a sorbent injec tion system would need to be installed upstream of the existing ESPs to address increased SO 3 formation. It should be noted that catalyst suppliers will not offer plume opacity guaran tees for boiler firing No. 6 fuel oil with
vanadium in the ash.

SCR operation on an oil-fired boiler must be carefully controlled to minimize NH 3 slip, which leads to formation of ammonium bisulfate (NH 4 HSO 4 ). This material forms a sticky solid that condenses at temper atures between approximately 415 and 475°F, which occur in the center of the air heater. Units that expe rience high bisulfate formation typically require regular cleaning of the air heaters to rem ove these deposits. One option to mitigateNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

27 NH 4 HSO 4 formation is to install a sorbent injection system after SCR and upstream of the ESP to scavenge SO 3 in the flue gas.

Finally, SCR operation with fuel oil systems has, in some cases, been adversely affected by potassium in the fuel oil ash. Potassium can deactivate the SCR catalyst. In some cases, catalyst cleaning is frequently required to regain lost activity of the catalyst.

For these reasons SCR NO X reduction technology is typica lly not recommended for boilers firing No. 6 fuel oil. To address potential bala nce-of-plant impacts, the SCR would have to be designed to limit SO 2 to SO 3 oxidation and limit ammonia slip (generally less than about 5 ppm), and would likely require installation of a sorbent injection system upstream of the existing ESPs. These design limitations will limit how aggressively the facility can operate
the SCR to reduce NOx emissions.

The performance of an SCR system is influen ced by several factors, including flue gas temperature, inlet NOx level, available catalyst surface area, volume and age of the catalyst, and the quantity of unreacted excess am monia acceptable in the flue gas (ammonia slip). In order to effectively reduce NOx, NH 3 injected into the flue gas must come into
contact with the NOx molecules within th e required temperature window and in the presence of active catalyst. Effective NOx control requires thorough NH 3 mixing and available active catalyst surface area.

Operating variables affecting the NOx control will fluctuate during normal boiler operations, including boiler load changes, low load operation, and toward the end of the catalyst life. Catalyst that has been in service for a period of time will have decreased performance because of normal deactivation and dete rioration. Catalyst that is no longer effective due to plugging, blinding or deactivation must be replaced.

SCR would pose significant engineering and design challenges on Oswego Units 5 & 6; however, SCR is considered a technically feasible retrofit NOx control system. Economic impacts associated with engineering/designi ng around those challenges are evaluated in Step 4 of the BART determination.

Based on emission rates achieved in practice at existing units, and taking into consideration the Oswego Unit 5 & 6 general arrangements, fuel characteristics, flue gas characteristics, and long-term operation of an SCR control system (including catalyst plugging and deactivation) it is anticipated that SCR coul d achieve a controlled NOx emission rate of 0.03 lb/mmBtu (30-day rolling average). An em ission rate of 0.03 lb/mmBtu is equivalentNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

28 to an average NOx concentration in the flue gas of approximately 22 ppmvd @ 3% O 2 . Reducing NOx emissions below 22 ppmvd @ 3% O 2 would tend to increase potential balance-of-plant impacts associated with the SCR, including increased ammonia slip,
increased SO 2 to SO 3 oxidation, and more frequent catalyst changes.

3.2.3 Innovative NOx Control Technologies

A number of innovative NOx control systems, in cluding multi-pollutant control systems, were identified as potential retrofit NOx control technologies during the review of available technologies. Innovative NOx control technologi es with potential application to Oswego Units 5 & 6 include boosted over-fire air (e.g., MobotecUSA’s ROFA ® system), advanced SNCR control systems (e.g., MobotecUSA’s Rotamix ® system), Enviroscrub’s multi-pollutant PahlmanTM process, NOxStarTM, J-Power’s REACT system, and Powerspan’s ECO technology. Innovative NOx control systems with potentia l application to Oswego Units 5 & 6 are
evaluated below.

3.2.3.1 Rotating Opposed Fired Air and Rotomix

Rotating opposed fired air (ROFA ® ) is a boosted overfire air system that includes a patented rotating injection system whic h includes asymmetrically placed air nozzles. 5 Like other OFA systems, ROFA stages the primary combustion zone to burn overall rich, with excess air added higher in the furnace to burn out products of incomplete combustion. The
rotational effect of the combustion air is indu ced by large ROFA fans in the upper furnace, and the ROFA nozzles are designed to increase turbulence within the furnace. Increased turbulence should allow for deeper combustion staging, and enable the furnace volume to be used more effectively for the combustion process.

The ROFA system consists of air injection boxes, duct work and supports, the ROFA fan, and control system instrumentation. To achieve rotation, secondary combustion air is pressurized by the ROFA fans and enters th e furnace through nozzles positioned to induce the combustion products to rotate and mix in the upper furnace sections. The fans required to produce the rotation can be large, and sp ace constraints on existing units can make the placement of the ROFA fans difficult.

The ROFA system also depends on deep staging to reduce initial NOx production. Burner stoichiometric ratios with a ROFA system ma y be as low as 0.80 to 0.85. Deep staging

5 See, MobotecUSA at www.mobotecusa.com

.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

29 also extends the combustion process higher in the furnace which can lead to higher upper furnace temperatures and higher furnace exit gas temperatures. Shifting temperature to the upper furnace can significantly impact boiler performance in the reheat and superheat
sections of the boiler.

MobotecUSA’s Rotamix ® system combines the rotating opposed overfire air system with urea injection into the flue gas (SNCR) to reduce NOx emissions. The turbulent air injection and mixing provided by ROFA may allow for more effective mixing of chemical reagents with the combustion products in the furnace. The turbulent mixing created by the ROFA system is designed to improve distribu tion of the ammonia or urea reagent and may reduce the quantity of reagent required by the SNCR control system.

As discussed in subsection 3.2.1.1, Oswego Un its 5 & 6 are currently equipped with lowNOx burners, OFA and FGR. The effectiveness of the existing combustion system is limited by operating issues associated with d eep staging in the primary burner zone and OFA jet penetration. The same operating issues would apply to the ROFA system. At similar burner stoichiometric ratios either combustion control system (i.e., LNB/OFA or LNB/ROFA) would be expected to achieve similar boiler NOx emissions.

Based on a review of available information, ROFA has been installed as a retrofit NOx control system on a limited number of coal-fi red boilers, and only one boiler greater than 200 MW in size. Although it may be technica lly feasible to apply the ROFA design to Oswego Units 5 & 6, there is no technical basi s to conclude that the ROFA design would provide additional NOx reduction beyond that achieved with modifying the existing OFA system. All OFA systems will be limited by the degree of staging and residence time in the furnace. Therefore, ROFA will not be evalua ted as a specific control alternative, but will be included in the overall evaluation of potentially feasible combustion controls.

Similarly, the technical and physical limitations affecting SNCR effectiveness described in subsection 3.2.2.1 would also apply to the Rotamix control system. Rotamix is a SNCR control system (i.e., ammonia injection system ) coupled with the ROFA rotating injection nozzle design. Technical limitations, including the physical size of the boiler and boiler residence time, would apply to the Rotamix control system. There is no technical basis to conclude that Rotamix urea injection design addresses these unresolved technical difficulties or provided additional NOx removal. Therefore, Rotomix will not be evaluated as a specific control alternative, but will be included in the overall evaluation of potentially feasible SNCR control systems.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

30 3.2.3.2 NO x Star Control System

NOxStar is a proprietary technology designed to reduce boiler NOx. The process continuously injects controlled quantities of an ammonia-based reagent with relatively small amounts of hydrocarbon (typically natural gas or propane) into the convective pass of the boiler at a temperature of around 1,600 to 1,800 o F. 6 At the elevated temperatures the hydrocarbon auto-ignites to form a plasma of free radicals which autocatalyzes the reaction
of NH 3 and NOx to form N 2 and H 2 O (similar to the SCR reactions shown in subsection 3.2.2.2).

The NOxStarTM concept was first demonstrated in 2001 at Mitsui Babcock’s 0.55 mmBtu coal-test facility using a single injection point . As a result of near ideal mixing, NOx reduction levels of up to 90% were achieved with acceptable ammonia slip levels. The NOxStarTM control system offers the potential to reduce NOx emissions without the need to install a solid catalyst layer (i.e., SCR), and without the associated operational issues such as chemical poisoning, physical plugging, sintering, pressure drop requiring new ID fans, and spent catalyst handling. The NOxStarTM concept should also minimize the conversion
of SO 2 to SO 3 , which can be a significant issue with SCR control.

The NOxStarTM process was demonstrated in full scale tests at TVA’s Kingston 9 Power Plant. Kingston 9 is a coal-fired 200 MW tange ntially fired boiler. Test results showed that the NOx reduction potential was a function of the flue gas temperature at the injection point, fuel sulfur content, and residence time downstream of the injection lances. NOx reductions were limited to appr oximately 50% of the inlet NOx rate. To provide additional NOx control a single layer of catalyst coul d be installed in the existing ductwork downstream of the ammonia/hydrocarbon injection system (NOxStarTM Plus). Excess ammonia injected in the flue gas would react with NOx in the presence of the catalyst to
form N 2 and H 2 O. As with more conventional SCR, the effectiveness of the catalyst layer would be a function of flue gas composition, residence time, NH 3 :NOx ratio, and flue gas
temperature.

At this point, the NOxStarTM technology has b een demonstrated only on a limited basis on large boilers. Potential NOx removal efficiencies would be a function of NH 3 -NOx mixing, flue gas temperature, flue gas composition, and residence time downstream of the injection lances. Achieving NOx removal efficiencies greater than approximately 50% may require

6 See, Morris, K.W., Hesselmann, G., NOxStarTM Plant Demonstration , Mitsui Babcock, not dated.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

31 the installation of a layer of SCR catalyst in the ductwork downstream of the ammonia/hydrocarbon injection system.

It is likely that NRG would be required to conduct extensive design engineering and testing to evaluate the technical feasibility and long- term effectiveness of these control systems on Oswego Units 5 & 6. Detailed design of the lances, mixing, optimization of the reagent supply across the boiler gas pass, flue gas temperatures and flow distribution would have to
be studied. It would also have to be determ ined whether sufficient space is available in the existing duct work to install a layer of catalyst.

Without significant engineering and testing it is not possible to determine whether technical difficulties associated with flue gas chemistry, residence time, and space limitations would preclude the successful use of these control sy stems on Oswego Units 5 & 6. BART does not require applicants to experience extende d time delays or resource penalties to allow research to be conducted on an emerging contro l technique. Therefore, at this time the NOxStarTM and NOxStarTM Plus control systems are not considered available NOx retrofit control systems for Oswego Units 5 & 6, and will not be further evaluated in the BART
determination.

3.2.3.3 Powerspan ECO Technology

Powerspan’s ECOTM process is a multi-polluta nt control technology designed to capture
SO 2 , NOx, and mercury from coal-fired boilers. The process utilizes a dielectric barrier discharge reactor to oxidize pollutants in the flue gas steam, followed by an ammonia wet scrubber and wet ESP for removal of oxidized po llutants and by-products. The technology produces a potentially saleable ammonium sulfate/ ammonium nitrate fertilizer by-product.

The ECOTM control system is designed fo r installation downstream of an existing particulate control device. Flue gas flows from the particulate control device to an electrocatalytic oxidation (ECO) reactor, where hydroxyl (OH) radicals and atomic oxygen (O) are formed by the reaction of high-energy electrons with water and oxygen molecules. 7 These radicals then react with polluta nts in the flue gas, oxidizing SO 2 to sulfuric acid and NOx to nitric acid (HNO 3 ).

7 The description for the ECOTM control technology was taken from: Status of Integrated Emission Control Process Development: Airborne and ReACT Process Technical Review , Section 2.0, EPRI, Palo Alto, CA: 2005. 1010338.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

32 Oxidized flue gas is then sent to a doubl e loop ammonia scrubber where the sulfuric and nitric acids are removed from the flue gas. In the upper loop of the scrubber, ammonia is added to react with the acids to form ammonium sulfate and nitrate. The lower loop of the scrubber cools and saturates the flue gas and concentrates the by-products for removal. Oxidation air is added to the lower loop to further oxidize sulfites and nitrites.

Following the ammonia scrubber, the flue gas enters a mist eliminator where entrained droplets are removed prior to the gas enteri ng a wet electrostatic precipitator (WESP).
Acid aerosols are collected in the WESP. So luble ammonium sulfate and nitrate exit the
ammonia scrubber in a bleed stream that is tr eated by filtration to remove ash and insoluble metal compounds. The stream is then passed through an activated carbon absorption bed for mercury removal. The purified by-product stream is then sent to a crystallizer where sulfate and nitrate crystals are formed by ev aporation. The crystals are then dried and granulated to form a fertilizer by-product that may be marketable depending on quality and
local market conditions.

The ECOTM technology has been pilot tested on a 1-MW equivalent slipstream at the R.E. Burger Plant located in Ohio. Followin g pilot testing, Powerspan built a 50 MW commercial demonstration unit at the same location. Emissions testing from the
commercial scale demonstration have shown th at the control techno logy can successfully
remove SO 2 , NOx, and mercury for coal-fired flue gas.

At this point, the ECOTM technology is no t considered a technically feasible and commercially available NOx retrofit control option for oil-fired boilers. The ECOTM technology is a multi-pollutant control technolog y that would have no practical application as a NOx-only retrofit control system on an oil-fired unit. Therefore, the ECOTM technology is not considered a technically f easible NOx retrofit control system for Oswego Units 5 & 6, and will not be evaluated further in the BART determination.

3.2.4 NOx Control - Summary

Results of Step 2 of the NOx BART Analysis (technical feasibility analysis of potential NOx control technologies) are summarized in Table 3-2.NRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT33Table 3-2Technical Feasibility of Potential NOxControl Technologies – Oswego Unit 3Controlled NOxEmissionRateIn Service onExisting PC BoilersControl TechnologyUnit 5 Unit 6 Yes NoTechnically Feasible andCommercially Available NOxRetrofit Control Technology?Baseline LNB/OFA/FGR0.22 0.19x Technically feasible.Optimize LNB/OFA/FGR with NeuralNetwork Control System0.21 0.18x Technically feasible.LN-REACH (pressure atomizer) plusmodified OFA0.18 0.17x Technically feasible.LN-REACH (steam atomizer) plusmodified OFA0.17 0.16Technically feasible. Steam would be supplied from theboiler during normal operation and from the existing auxiliaryboiler during startup.Gas Co-Firing (150 MW) Unit 6NotAvailableNot FeasiblexUnit 6 is currently equipped to co-fire natural gas. Based onavailability, natural gas co-firing is limited to approximately150 MW (heat input). Additional co-firing, or co-firing Unit5, would require installation of a new natural gas pipeline,which is not considered a technically feasible option.However, co-firing natural gas at loads above approximately300 to 400 MW is not a technically feasible option due toboiler tightness, residence time, and FEGT issues. Co-firingnatural gas at the levels needed for effective NOx controlwould require significant modifications to the boiler pressureparts, and is not a practical control option for Unit 6.NRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT34Table 3-2 continued:Controlled NOxEmissionRateIn Service onExisting PC BoilersControl TechnologyUnit 5 Unit 6 Yes NoTechnically Feasible andCommercially Available NOxRetrofit Control Technology?LN-REACH (pressure atomizer) plusmodified OFA and Gas ReburnNotAvailableNot FeasiblexLN-REACH (steam atomizer) plusmodified OFA and Gas ReburnNotAvailableNot FeasiblexThe gas reburn technically is also subject to the tight boiler,residence time, and FEGT issues discussed in subsection3.2.1.4. At the natural gas heat input levels needed foreffective NOx control at boiler loads above approximately400 MW, the gas reburn option would likely result insignificant FEGT issues, and would not be feasible withoutsignificant modifications to the boiler SH/RH pressure parts.Therefore, Gas Reburn is not considered a technically feasibleoption on Unit 6. Using gas rebrrn on both units wouldrequire installation of a new natural gas pipeline, which is notconsidered a technically feasible option.LN-REACH (pressure atomizer) plusmodified OFA and FLGR0.13 0.13xLN-REACH (steam atomizer) plusmodified OFA and FLGR0.12 0.12xFLGR is a technically feasible option on Units 5 & 6 utilizingnatural gas currently available at the facility. To provide theresidence time needed for effective NOx control, FLGRwould be coupled with upgraded burners and modified OFA.In addition, heat input from natural gas would be limited toapproximately 4% of the total boiler heat input to each boilerto minimize potential FEGT issues.LN-REACH (pressure atomizer) plusmodified OFA and SNCR0.14 0.14xLN-REACH (steam atomizer) plusmodified OFA and SNCR0.13 0.13xSNCR (coupled with optimizing the combustion system andOFA system) is a technically feasible NOx control option forboth units. Effectiveness of the option would be limited byboiler size, flue gas characteristics, and operational limitations(e.g., designing the system to achieve adequate mixing withinthe desired temperature window).NRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT35Table 3-2 continued:Controlled NOxEmissionRateIn Service onExisting PC BoilersControl TechnologyUnit 5 Unit 6 Yes NoTechnically Feasible andCommercially Available NOxRetrofit Control Technology?SCR0.030.03 xAlthough not recommended on an oil-fired boiler, SCR is atechnically feasible NOx control option. Effectiveness of thesystem would be limited by the fuel and fuel gascharacteristics (e.g., vanadium concentration), SO2to SO3conversion, ammonia slip, and other potential balance-ofplant impacts.Rotating Overfire Air (ROFATM)NA NAROFA has been demonstrated on smaller boilers, and wouldbe a technically feasible retrofit control technology.However, there is no technical basis to conclude that ROFAwill provide additional NOx control beyond that achievablewith modified OFA. Therefore,ROFA will be included in theevaluation of other OFA control systems.RotamixTMNA NARotamix control systems have been demonstrated on smallerboilers. However, there is no technical basis to conclude thatRotamix will provide additional NOx control beyond thatachievable with other SNCR control systems. Therefore,Rotamix will be included in the evaluation of other SNCRcontrol systems.NOxStarTM and NOxStarTM Plus Controls NANANOxStarTM has been demonstrated on a limited number ofcoal-fired boilers. Based on a review of available informationit was determined that, at this time, this control technology isnot a technically feasible and commercially available NOxretrofit control technology for Oswego Units 5 & 6.Powerspan ECO TechnologyNANAThe ECO control system has been demonstrated on a limitednumber of coal-fired boilers. Based on a review of availableinformation it was determined that, at this time, this controltechnology is not a technically feasible and commerciallyavailable NOx retrofit control technology for Oswego Units 5& 6.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

36 3.3 Step 3: Evaluate Control Effectiv eness of Remaining Control Technologies

The technically feasible and commercially available NO x retrofit control technologies are listed in Table 3-3 for Oswego Units 5 & 6. The effectiven ess of each control technology was evaluated in Step 2. Technically feasible control technologi es are listed in Table 3-3 in descending order of control efficiency.

Table 3-3 Technically Feasible NO x Control Technologies Oswego Units 5 & 6

Control Technology Unit 5
Controlled NOx Emissions 30-day rolling average (lb/mmBtu) Unit 6
Controlled NOx Emissions 30-day rolling average (lb/mmBtu)

SCR 0.03 0.03 LN-REACH (steam atomizer) plus modified OFA and FLGR 0.12 0.12

LN-REACH (steam atomizer) plus modified OFA plus SNCR 0.13 0.13

LN-REACH (pressure atomizer) plus modified OFA and FLGR 0.13 0.13

LN-REACH (pressure atomizer) plus modified OFA plus SNCR 0.14 0.14

LN-REACH (steam atomizer) plus modified OFA 0.17 0.16

LN-REACH (pressure atomizer) plus modified OFA 0.18 0.17

Optimize LNB/OFA/FGR with Neural Network Control System 0.21 0.18

Baseline LNB/OFA/FGR 0.22 0.19NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

37 3.4 Step 4: Evaluate the Technically Feasible NOx Control Technologies

3.4.1 NO x Control Technologies – Economic Evaluation

The most effective NO x retrofit control systems, in terms of reduced emissions, that are considered to be technically feasible for Oswe go Units 5 & 6, include post-combustion SCR. The effectiveness of an SCR control system is dependent on several site-specific system variables, including fuel characteristics, fl ue gas characteristics, catalyst layers, NH 3 -to-NOx stoichiometric ratio, vanadium and potassium in the fuel oil ash, NH 3 slip, and catalyst plugging/deactivation.

FLGR and SNCR control technologies provide the next most effective NOx control. Either option requires combustion control modifications (i.e., oversized LN-REACH and modified OFA) to provide adequate flue gas mixing and residence times. Combustion control modifications (i.e., LN-REACH and modified OF A) are the next most effective NOx control options. LN-REACH combustion technology and modifying the existing OFA ports to provide more effective jet penetration, is a technica lly feasible NOx control option. The LN-REACH burner technology can be designed with either mechanical pressurized or steam pressurized burner nozzles. Based on information from burner vendors, it is anticipated that steam pressurized nozzles would provide somewhat better atomization and flue gas mixing. Finally, installation of a Neural Network control system would provide some NOx control beyond the
baseline emissions.

Control systems that require natural gas co-firi ng at levels above approximately 300 to 400 MW, including natural gas co-firing and gas reburn, are not considered technically feasible due to boiler tightness, residence time, and FEGT li mitations. In addition, these co-firing options would require the facility to subscribe to a sp ecific quantity of natural gas, which cannot be guaranteed by the facility due to boiler opera tions. Furthermore, because only a limited quantity of natural gas is available at the sta tion, gas reburn and gas co-firing control systems are not considered an available control option for Unit 5.

Economic impacts associated with the potentiall y feasible NOx control systems were evaluated in accordance with EPA guidelines (40 CFR Pa rt 51 Appendix Y) and the NYDEC Air Guide 20 - Economic and Technical Analysis for Reas onably Available Control Technology. For the economic impact analysis, projected annual emi ssions (tpy) were calculated based on a 3.2% baseline capacity factor for Oswego Units 5 & 6. A 3.2% capacity factor is equivalent to the highest 12-month capacity factor for Unit 5 duri ng the baseline period, and is representative of actual option of the units over the past several years.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

38 Cost estimates were compiled from a number of data sources. Major equipment costs were developed based on equipment costs recently de veloped for similar projects, taking into consideration site-specific retrofit challenges and limitations. Capital costs include the equipment, material, labor, and all other direct costs needed to retrofit Oswego Units 5 & 6 with the control technologies.

Fixed and variable O&M costs were develope d for each control system. Fixed O&M costs include operating labor, maintenance labor, main tenance material, and administrative labor.
Variable O&M costs include the cost of cons umable, including reagent (e.g., ammonia), byproduct management, water consumption, and aux iliary power requirements. Auxiliary power requirements reflect the additional power requirements associated with operation of the new control technology, including operation of any new ID fans as well as the power requirements for pumps, reagent handling, and by-product handling.

Summarized in Table 3-4 are the expected c ontrolled NOx emission rates, and annual NOx mass emissions, associated with each technically feasible retrofit technology. Table 3-5 provides a budgetary capital cost estimate for each control system. Tables 3-6 and 3-7 summarize the total annual costs and average cost effectiveness of each control system on Units 5 & 6, respectively. More detailed budgetary cost estimates for each control technology are
included in Attachment A.NRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT39Table 3-4Annual NOx Emissions*Unit 5 Unit 6Control TechnologyNOxEmissionRate(lb/mmBtu)Annual NOxEmissions(tpy)AnnualReduction inEmissions(tpy frombaseline)NOxEmissionRate(lb/mmBtu)Annual NOxEmissions(tpy)AnnualReduction inEmissions(tpy frombaseline)SCR0.03 33.0 209.1 0.03 33.2 176.9LN-REACH (steam atomizer) plusmodified OFA and FLGR0.12 132.1 110.0 0.12 132.7 77.4LN-REACH (steam atomizer) plusmodified OFA plus SNCR0.13 143.1 99.0 0.13 143.8 66.3LN-REACH (pressure atomizer) plusmodified OFA and FLGR0.13 143.1 99.0 0.13 143.8 66.3LN-REACH (pressure atomizer) plusmodified OFA plus SNCR0.14 154.1 88.0 0.14 154.8 55.3LN-REACH (steam atomizer) plusmodified OFA0.17 187.1 55.0 0.17 177.0 33.1LN-REACH (pressure atomizer) plusmodified OFA0.18 198.1 44.0 0.18 188.0 22.1Optimize LNB/OFA/FGR with NeuralNetwork Control System0.21 231.1 11.0 0.18 199.1 11.0Baseline LNB/OFA/FGR0.22 242.1 -- 0.19 210.1 --*Annual emissions for each control option were calculated using a 3.2% capacity factor for each unit, based on historical annual hours of operation.NRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT40Table 3-5NOx Emission Control SystemCapital Cost SummaryControl TechnologyTotal CapitalInvestment*($)Total CapitalInvestment($/kW-gross)Annual CapitalRecovery Cost($/year)SCR$104,400,000 $122.8 $14,864,200LN-REACH (steam atomizer) plusmodified OFA and FLGR$26,820,000 $31.6 $3,818,600LN-REACH (steam atomizer) plusmodified OFA plus SNCR$13,200,000 $15.5 $1,879,400LN-REACH (pressure atomizer) plusmodified OFA and FLGR$23,220,000 $27.3 $3,306,000LN-REACH (pressure atomizer) plusmodified OFA plus SNCR$9,600,000 $11.3 $1,366,800LN-REACH (steam atomizer) plusmodified OFA$5,940,000 $7.0 $845,700LN-REACH (pressure atomizer) plusmodified OFA$2,340,000 $2.8 $333,200Optimize LNB/OFA/FGR withNeural Network Control System$1,200,000 $1.4 $170,900* Capital costs include the cost of major components and indirect installation costs such as foundations,mechanical erection, electrical,piping, and insulation for the control system.NRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT41Table 3-6Oswego Unit 5NOx Emission Control - Cost Effectiveness*Control TechnologyAnnual CapitalRecovery Cost($/year)AnnualOperatingCosts($/year)Total AnnualCosts($/year)AnnualEmissionReduction(tpy)Average CostEffectiveness($/ton)SCR $14,864,200 $423,800 $15,288,000 209.1 $73,113LN-REACH (steam atomizer) plusmodified OFA and FLGR$3,818,600 $297,700 $4,116,300 110.0 $37,421LN-REACH (steam atomizer) plusmodified OFA plus SNCR$1,879,400 $317,800 $2,197,200 99.0 $22,194LN-REACH (pressure atomizer) plusmodified OFA and FLGR$3,306,000 $297,700 $3,603,700 99.0 $36,401LN-REACH (pressure atomizer) plusmodified OFA plus SNCR$1,366,800 $317,600 $1,684,400 88.0 $19,141LN-REACH (steam atomizer) plusmodified OFA$845,700 $54,800 $900,500 55.0 $16,873LN-REACH (pressure atomizer) plusmodified OFA$333,200 $51,700 $384,500 44.0 $8,748Optimize LNB/OFA/FGR with NeuralNetwork Control System$170,900 $300,000 $470,900 11.0 $42,809* Total annual costs and annual emission estimates for each control option were calculated based on a 3.2% capacity factor.NRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT42Table 3-7Oswego Unit 6NOx Emission Control - Cost Effectiveness*Control TechnologyAnnual CapitalRecovery Cost($/year)AnnualOperatingCosts($/year)Total AnnualCosts($/year)AnnualEmissionReduction(tpy)Average CostEffectiveness($/ton)SCR $14,864,200 $423,800 $15,288,000 176.9 $86,422LN-REACH (steam atomizer) plusmodified OFA and FLGR$3,818,600 $297,700 $4,116,300 77.4 $53,182LN-REACH (steam atomizer) plusmodified OFA plus SNCR$1,879,400 $317,800 $2,197,200 66.3 $33,140LN-REACH (pressure atomizer) plusmodified OFA and FLGR$3,306,000 $297,700 $3,603,700 66.3 $54,354LN-REACH (pressure atomizer) plusmodified OFA plus SNCR$1,366,800 $317,600 $1,684,400 55.3 $30,459LN-REACH (steam atomizer) plusmodified OFA$845,700 $54,800 $900,500 33.1 $27,205LN-REACH (pressure atomizer) plusmodified OFA$333,200 $51,500 $384,900 22.1 $17,416Optimize LNB/OFA/FGR with NeuralNetwork Control System$170,900 $300,000 $470,900 11.0 $42,809* Total annual costs and annual emission estimates for each control option were calculated based on a 3.2% capacity factor.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

43 The average annual cost effectiveness of the SCR control option on Units 5 & 6 is in the range of $73,113/ton (Unit 5) to $86,422/ton (Unit 6). Equipment costs, retrofit challenges, and auxiliary equipment costs, including the ammoni a handling and delivery systems, all have a significant impact on the cost of SCR control. There are also significant annual operating costs with SCR control, including energy co sts associated with the additional pressure drop across the SCR, reactant costs, and catalyst re placement costs. Although retrofit SCR has the potential to achieve the lowest NOx emission rates, it is an expensive NOx control option and is clearly not cost effective on Oswego Units 5 & 6.

The second most effective NOx control retrofit options include FLGR. The FLGR process injects natural gas above the main combustion furnace to reduce NOx to N 2 . As described in subsection 3.2.1.6, the natural gas reburn fuel injection level in the upper furnace must be
installed where sufficient residence time exists fo r the fuel to complete its burnout process. To provide sufficient residence time, installation of FLGR control systems on the Oswego boilers would be coupled with the upgraded LN-REA CH and modified OFA controlled systems
described in section 3.2.1.2.

Total capital costs for the FLGR and combustion control system upgrades would be in the range of $23.2 to $26.8M, or approximately $27 to $31/kW-gross. Of this total, approximately
85% of the costs are associated with the FLGR control system. Capital costs associated with FLGR include the installation of gas injectors (gen erally two or more levels of injectors are required), modifications to the boilers to provide access at the optimal temperature zone, installation of additional safety and temperature sensors in the reburn zone, and modifications to the units’ existing control system. Typically , each gas injector has an automatic modulating flow control valve to optimize flow to the indi vidual injectors. O&M costs are somewhat less than control options that include a reactant (e.g ., ammonia or urea), but include costs associated with securing the reburn fuel (natural gas), as well as energy costs incurred due to slight loss in overall boiler efficiency. The average cost effectiveness of FLGR control ranges from $36,401/ton (Unit 5) to $54,353/ton (Unit 6). Th e control system is less cost effective on Unit
6 because of the unit’s lower baseline emission ra te. Because of the capital costs associated with FLGR and the relatively small reduction in annual NOx emissions (from baseline), FLGR is not a cost effective NOx control option for Oswego Units 5 & 6.

The SNCR control options also have relatively high average cost effectiveness and high incremental cost effectiveness (compared to the corresponding combustion control option without SNCR). As with FLGR, to be effectiv e, SNCR control must be combined with the combustion modifications to provide adequate mi xing and residence time. The combination ofNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

44 SNCR combined with upgrading the existing combustion controls has an average cost effectiveness of $19,141/ton (Unit 5 with pressure atomizers) to $33,140/ton (Unit 6 with steam atomizers). In addition, the incremental cost effectiveness of SNCR ranges from approximately $29,000/ton on Unit 5 to $39,000/ton on Unit 6 (compared to upgrading the combustion controls without SNCR).

Capital costs and annual O&M costs both contribute to the relatively high cost effectiveness of SNCR control. Capital costs of the SNCR system are estimated to be in the range of $8.5/kWgross. Capital costs include the urea handling and storage system, urea injection system, and control system. In addition, installation of SN CR typically requires modifications to the units’
air heaters. Modifications to the air heat ers are required to minimize the potential for ammonium bisulfate formation and the resulting operating impacts. Annual O&M costs associated with SNCR include auxiliary power cost s associated with the urea injection system and the reagent costs. The significant increase in total annual costs coupled with the relatively small decrease in annual emissions (approxi mately 25% from the corresponding combustion control system option) results in the relativ ely high average cost effectiveness and high incremental cost effectiveness of SNCR control. Thus, SNCR is not a cost effective retrofit NOx control system on Oswego Units 5 & 6.

Combustion modifications (including LN-REACH burners and modified OFA) have average cost effectiveness values ranging from $8,748/ton (Unit 5 with pressure atomizers) to $17,416/ton (Unit 6 with pressure atomizers). Co mbustion control modifications are less costeffective on Unit 6 because of its lower baseline NOx emission rate. On both units, the LNREACH option with pressure atomization is more cost effective than the LN-REACH option
with steam atomization. Ca pital costs associated with upgrading the combustion control systems, including new oversized LN-REACH bur ners and physical modifications to the OFA ports, are estimated to be in the range of approximately $2.8/kW-gross (with pressure atomization) to approximately $7.0/kW-gross (with steam atomization). Operating costs associated with combustion control options are generally insignificant.

Although combustion system modifications ar e significantly less expensive than the postcombustion control systems, combustion controls are still not cost effective on Oswego Units 5 & 6. Both units are already equipped with LN-REACH burners, OFA, and FGR, and both units already achieve relatively low NOx emission rat es. Replacing the existing combustion controls
with oversized LN-REACH burners and modifying the OFA system to provide more residence time and mixing should reduce NOx emissions by approximately 15 to 20% (depending on the baseline NOx emission rate). However, a 15% reduction in NOx emissions results in aNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

45 relatively minor decrease in annual NOx emissi ons because of the units’ baseline capacity
factors.

During the baseline period of 2007 – 2009, annual capacity factors for both units ranged from 0.52% (Unit 5, 2009) to 2.68% (Unit 5, 2007). The highest 12-month rolling average capacity factor during the baseline period was 3.2% (Unit 5), which was used to calculate baseline and projected annual emissions. The maximum annua l capacity factor for either unit since 2005 was 9.56% (Unit 5, 2005). These low capacity f actors, coupled with the existing combustion controls, lead to low baseline annual NOx emissi ons, and higher cost effectiveness numbers. Assuming the units continue to operate at low capacity factors, combustion modifications
would not be cost effective.

The final NOx control option involves installing a neural network (NN) control system on the units to provide some additional NOx control w ith the existing LN-REACH and OFA systems. Based on control achieved at other existing units, it is expected that a NN control system could achieve a reduction of approximately 5% in th e long-term average NOx emission rate. Capital costs of a NN control system are in the range of $1.2M, or $1.4/kW-gross. Operating costs associated with NN control are generally insi gnificant; however, based on experience with NN control systems on existing units, it was determ ined that one full-time operator would be needed to ensure proper operation of the ne ural network control system. Taking into consideration potential emission reductions, capita l, and operating costs, the average cost effectiveness of NN control would be in the range of $43,000/ton. Because of the relatively small reduction in annual NOx emissions, NN cont rol is not cost effective on Oswego Units 5
& 6.

3.4.2 NO x Control Technologies – Environmental Impacts

Combustion modifications designed to decrease NOx formation (e.g., lower temperature and less oxygen availability) also tend to increase the formation and emission of CO. Therefore, the combustion controls must be designed to reduce the formation of NOx while maintaining CO at an acceptable level. Other than the NOx /CO trade-off, there are no environmental issues associated with using combustion controls to reduce NOx emissions.

SNCR and SCR control systems have several pot ential collateral environmental consequences. 8 First, in order to maintain low NOx emissi ons, excess reactant (urea or ammonia) will pass through the control system. Excess urea/ammonia will tend to increase as NOx emissions are

8 See, Hinton, W.S., Cushing, K.M., Gooch, J.P., “B alance-of-Plant Impacts As sociated with SCR/SNCR Installations”, proceedings of the ICAC Forum, 2002.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

46 driven lower and lower. On an SCR system, a mmonia slip also tends to increase as the catalyst becomes plugged, blinded, and deactivated.

Undesirable reactions can occur with SNCR a nd SCR control systems. With SNCR, excess reagent in the flue gas can react with sulfur compounds in the flue gas to form ammonium bisulfate and lead to significant plugging of downstream equipment. To minimize potential impacts of reactant slip and ammonium bisulfate formation, the SNCR control system would have to be designed with a maximu m slip of approximately 5 ppm.

With SCR, a fraction of the SO 2 in the flue gas (greater than 1.5% depending on the vanadium content of the fuel oil ash) will oxidize to SO 3 in the presence of the SCR catalyst. SO 3 can react with water to form sulfuric acid mist or with ammonia slip to form ammonium sulfate and
ammonium bisulfate. Ammonium bisulfate is a sticky compound that can adhere to ductwork downstream of the SCR and create significant opera tional and maintenance problems. Sulfuric
acid mist and ammonium sulfate are classified as condensable particulates; thus, installation of
an SCR can result in increased PM 2.5 emissions.

On-site ammonia storage also increases the ri sks associated with an accidental ammonia release. Depending on the type, concentrati on, and quantity of ammonia used, ammonia storage/handling will be subject to regula tion as a hazardous substance under CERCLA, Section 313 of the Emergency Planning and Co mmunity Right-to-Know Act, Section 112(r) of the Clean Air Act, and Section 311(b)(4) of the Cl ean Water Act. One strategy that can be used
to minimize the risk associated with on-site ammonia handling, is to design the ammonia handling system as a urea-to-ammonia conversion sy stem. Urea can be delivered to the station as an aqueous solution or as a dry solid, a nd urea storage/handling does not create the process safety concerns associated with ha ndling anhydrous ammonia.

3.4.3 NO x Control Technologies – Energy Impacts

All of the NOx retrofit control systems require auxiliary power. Auxiliary power requirements associated with the LNB/OFA control systems are generally insignificant; however, OFA and FLGR systems designed to increase boiler turbulen ce can require relatively large booster fans and increased auxiliary power requirements. A uxiliary power requirements associated with SNCR include power requirements for the urea handl ing and injection system. Auxiliary power requirements associated with S CR include the ammonia injection system and additional fan power to overcome pressure drop through SCR. Energy impacts associated with each control technology were included in the BART economic impact evaluation as an annual auxiliary
power cost.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

47 A summary of the Step 4 economic and environmen tal impact analysis is provided in Tables 3- 8 and 3-9 for Oswego Units 5 & 6, respectively.

3.5 NOx RACT/BACT Control Conclusions

Based on the evaluation of capital costs, operating costs, and annual emission reductions included herein, none of the technically feasible and ava ilable NOx control options are cost effective on Oswego Units 5 & 6. Several site-specific factor s contribute to this result. First, there are significant capital requirements associated with the post-combustion control systems, including SCR, FLGR, and SNCR. Both equipment costs a nd retrofit challenges contribute to these capital costs. Capital costs of post-combustion cont rol range from approximately $11.3/kW-gross (SNCR with combustion control modifications) to as high as $122.8/kW-gross (SCR). Capital costs associated with combustion control system modifications are significantly less ranging from $2.8/kW-gross (with pressure atomization) to $7.0/ton (with steam atomization).

More importantly, baseline annual NOx emissions from both units are only in the range of approximately 240 tpy. Baseline annual NOx emis sions are low because of the low capacity factors achieved by both units during the baseline peri od. As discussed above, both units have had capacity factors of 3.2% or less during the baselin e period, and, in fact, neither unit has had a capacity factor above 10% since 2001. Low capacity factors result in low baseline NOx emissions.

Finally, both units are currently equipped w ith low-NOx combustion controls, including LNREACH, overfire air (OFA), and flue gas recirculation (FGR) controls, and both units already achieve relatively low NOx emission rates (i.e., baseline NOx emission rates for Oswego Units 5 & 6 are 0.22 lb/mmBtu and 0.19 lb/mmBtu, respectively). Low baseline NOx emission rates, coupled with the low unit capacity factors, result in b aseline annual NOx emissions of only about 240 tpy
from each units. The low baseline NOx emission ra tes contribute significantly to the high costeffectiveness of potential retrofit NOx control techno logies. Assuming the units continue to operate at low capacity factors, none of the potential NOx control systems, including combustion modifications, would be cost effective.NRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT48Table 3-8Oswego Unit 5Summary of NOxBART Impact AnalysisControl TechnologyControlledAnnualEmissions(tpy)AnnualEmissionReductions(tpy)Total AnnualCosts($/year)Average CostEffectiveness($/ton)Summary of Environmental ImpactsSCR33.0 209.1$15,288,000 $73,113Ammonia slip, increased SO2to SO2conversion, increased condensible PMemissions, and ammonia storage.LN-REACH (steam atomizer) plusmodified OFA and FLGR132.1 110.0$4,116,300 $37,421Potential increase in CO emissions.LN-REACH (steam atomizer) plusmodified OFA plus SNCR143.1 99.0$2,197,200 $22,194Reactant storage (ammonia or urea),ammonia slip emissions, and the potentialto form ammonia bisulfate.LN-REACH (pressure atomizer) plusmodified OFA and FLGR143.1 99.0$3,603,700 $36,401Potential increase in CO emissions.LN-REACH (pressure atomizer) plusmodified OFA plus SNCR154.1 88.0$1,684,400 $19,141Reactant storage (ammonia or urea),ammonia slip emissions, and the potentialto form ammonia bisulfate.LN-REACH (steam atomizer) plusmodified OFA187.1 55.0$900,500 $16,873NoneLN-REACH (pressure atomizer) plusmodified OFA198.1 44.0$384,500 $8,748NoneOptimize LNB/OFA/FGR withNeural Network Control System231.1 11.0$470,900 $42,809NoneBaseline LNB/OFA/FGR242.1 ------NANRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT49Table 3-9Oswego Unit 6Summary of NOxBART Impact AnalysisControl TechnologyControlledAnnualEmissions(tpy)AnnualEmissionReductions(tpy)Total AnnualCosts($/year)Average CostEffectiveness($/ton)Summary of Environmental ImpactsSCR33.2 176.9$15,288,000 $86,422Ammonia slip, increased SO2to SO2conversion, increased condensible PMemissions, and ammonia storage.LN-REACH (steam atomizer) plusmodified OFA and FLGR132.7 77.4$4,116,300 $53,182Potential increase in CO emissions.LN-REACH (steam atomizer) plusmodified OFA plus SNCR143.8 66.3$2,197,200 $33,140Reactant storage (ammonia or urea),ammonia slip emissions, and the potentialto form ammonia bisulfate.LN-REACH (pressure atomizer) plusmodified OFA and FLGR143.8 66.3$3,603,700 $54,354Potential increase in CO emissions.LN-REACH (pressure atomizer) plusmodified OFA plus SNCR154.8 55.3$1,684,400 $30,459Reactant storage (ammonia or urea),ammonia slip emissions, and the potentialto form ammonia bisulfate.LN-REACH (steam atomizer) plusmodified OFA177.0 33.1$900,500 $27,205NoneLN-REACH (pressure atomizer) plusmodified OFA188.0 22.1$384,900 $17,416NoneOptimize LNB/OFA/FGR withNeural Network Control System199.1 11.0$470,900 $42,809NoneBaseline LNB/OFA/FGR210.1 ------NANRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

50 NRG – Oswego Generating Station Units 5 & 6 RACT / BART Engineering Study

Attachment A NOx Control System – Budgetary Cost EstimatesNRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

51 Control Option: Neural Network Control System

Unit 5

Unit 6 CAPITAL COSTS [$] Basis Cost of Emissions Control Eq uipment Including Installation

NOx Control Equipment (Neural Network Control) $1,000,000 Based estimated cost for Neural Network installation (S&L cost database). Includes purchased equipment cost and installation.

Contingency $200,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $1,200,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs (Capital Recover Factor x Total Capital Requirement) $170,900 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $0 65 $ per MWh
0 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $0 Maintenance Costs $300,000 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $300,000

TOTAL ANNUAL COST Annualized Capital Cost $170,900 Annual Operating Cost $300,000 Total Annual Cost $470,900

CAPITAL COSTS [$] Basis Cost of Emissions Control E quipment Including Installation

NOx Control Equipment (Neural Network Control) $1,000,000 Based estimated cost for Neural Network installation (S&L cost database). Includes purchased equipment cost and installation.

Contingency $200,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $1,200,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years)

Annualized Capital Costs (Capital Recover Factor x Total Capital Requirement) $170,900 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $0 65 $ per MWh
0 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $0 Maintenance Costs $300,000 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $300,000

TOTAL ANNUAL COST Annualized Capital Cost $170,900 Annual Operating Cost $300,000 Total Annual Cost $470,900NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

52 Control Option: LN-REACH (pressure atomizers) and Modified OFA

Unit 5

Unit 6 CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (oversized LN-REACH with pressure atomizers and modified OFA) $1,950,000 Based on estimated LNR(P)+OFA+FGR retrofit cost (S&L cost database). Includes purchased equipment cost and installation.

Contingency $390,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $2,340,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $333,200 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $0 65 $ per MWh
0 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $0 Maintenance Costs $51,700 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $51,700

TOTAL ANNUAL COST Annualized Capital Cost $333,200 Annual Operating Cost $51,700 Total Annual Cost $384,900

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (oversized LN-REACH with pressure atomizers and modified OFA) $1,950,000 Based on estimated LNR(P)+OFA+FGR retrofit cost (S&L cost database). Includes purchased equipment cost and installation.

Contingency $390,000 20% of direct and indirect capital cost s. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $2,340,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $333,200 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $0 65 $ per MWh
0 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $0 Maintenance Costs $51,700 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $51,700

TOTAL ANNUAL COST Annualized Capital Cost $333,200 Annual Operating Cost $51,700 Total Annual Cost $384,900NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

53 Control Option: LN-REACH (steam atomizers) and Modified OFA

Unit 5

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (oversized LN-REACH with steam atomizers and modified OFA) $4,950,000 Based on estimated LNR(S)+OFA+FGR retrofit cost (S&L cost database). Includes purchased equipment cost and installation.

Contingency $990,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $5,940,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $845,700 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $0 65 $ per MWh
0 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $2,200 Includes atomizing steam costs Maintenance Costs $52,600 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $54,800

TOTAL ANNUAL COST Annualized Capital Cost $845,700 Annual Operating Cost $54,800 Total Annual Cost $900,500

Unit 6

CAPITAL COSTS [$] Basis Cost of Emissions Control E quipment Including Installation NOx Control Equipment (oversized LN-REACH with steam atomizers and modified OFA) $4,950,000 Based on estimated LNR(S)+OFA+FGR retrofit cost (S&L cost database). Includes purchased equipment cost and installation.

Contingency $990,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $5,940,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $845,700 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $0 65 $ per MWh
0 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $2,200 Includes atomizing steam costs Maintenance Costs $52,600 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $54,800

TOTAL ANNUAL COST Annualized Capital Cost $845,700 Annual Operating Cost $54,800 Total Annual Cost $900,500NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

54 Control Option: LN-REACH (pressure atomizers) + Modified OFA + SNCR

Unit 5

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (oversized LN-REACH with pressure atomizers and modified OFA) $1,950,000 Post-Combustion NOx Control (SNCR) $6,050,000 Contingenc y $1,600,000 20% Document, Table 6-1. Total Capital Requirement (TCR) $9,600,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $1,366,800 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $17,100 65 $ per MWh
938 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $154,400 Includes reagent costs Maintenance Costs $146,100 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $317,600

TOTAL ANNUAL COST Annualized Capital Cost $1,366,800 Annual Operating Cost $317,600 Total Annual Cost $1,684,400 Based on estimated LNR(P)+OFA+FGR+SNCR retrofit cost (S&L cost database). Includes purchased equipment costs for combustion controls, SNCR, and auxiliary equipment including installation.

Unit 6

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (oversized LN-REACH with pressure atomizers and modified OFA) $1,950,000 Post-Combustion NOx Control (SNCR) $6,050,000 Contingency $1,600,000 20% Document, Table 6-1. Total Capital Requirement (TCR) $9,600,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $1,366,800 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $17,100 65 $ per MWh
938 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $154,400 Includes reagent costs Maintenance Costs $146,100 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $317,600

TOTAL ANNUAL COST Annualized Capital Cost $1,366,800 Annual Operating Cost $317,600 Total Annual Cost $1,684,400 Based on estimated LNR(P)+OFA+FGR+SNCR retrofit cost (S&L cost database). Includes purchased equipm ent costs for combustion controls, SNCR, and auxiliary equipment including installation.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

55 Control Option: LN-REACH (steam atomizers) + Modified OFA + SNCR

Unit 5

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (oversized LN-REACH with steam atomizers and modified OFA) $4,950,000 Post-Combustion NOx Control (SNCR) $6,050,000 Contingenc y $2,200,000 20% Document, Table 6-1. Total Capital Requirement (TCR) $13,200,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $1,879,400 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $17,100 65 $ per MWh
938 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $154,500 Includes reagent costs Maintenance Costs $146,200 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $317,800

TOTAL ANNUAL COST Annualized Capital Cost $1,879,400 Annual Operating Cost $317,800 Total Annual Cost $2,197,200 Based on estimated LNR(S)+OFA+FGR+SNCR retrofit cost (S&L cost database). Includes purchased equipment costs for combustion controls, SNCR, and auxiliary equipment including installation.

Unit 6

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (oversized LN-REACH with steam atomizers and modified OFA) $4,950,000 Post-Combustion NOx Control (SNCR) $6,050,000 Contingency $2,200,000 20% Document, Table 6-1. Total Capital Requirement (TCR) $13,200,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $1,879,400 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $17,100 65 $ per MWh
938 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $154,500 Includes reagent costs Maintenance Costs $146,200 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $317,800

TOTAL ANNUAL COST Annualized Capital Cost $1,879,400 Annual Operating Cost $317,800 Total Annual Cost $2,197,200 Based on estimated LNR(S)+OFA+FGR+SNCR retrofit cost (S&L cost database). Includes purchased equipm ent costs for combustion controls, SNCR, and auxiliary equipment including installation.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

56 Control Option: LN-REACH (pressure atomizers) + Modified OFA + FLGR

Unit 5

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (oversized LN-REACH with pressure atomizers and modified OFA) $1,950,000 Post-Combustion NOx Control (FLGR) $17,400,000

Contingency $3,870,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $23,220,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $3,306,000 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $1,500 65 $ per MWh
82 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $13,400 Includes costs associated with reduced boiler efficiency Maintenance Costs $282,800 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $297,700

TOTAL ANNUAL COST Annualized Capital Cost $3,306,000 Annual Operating Cost $297,700 Total Annual Cost $3,603,700 Based on estimated LNR(P)+OFA+FGR+FLGR retrofit cost (S&L cost database). Includes purchased equipment costs for combustion controls, FLGR and auxiliary equipment including installation.

Unit 6

CAPITAL COSTS [$] Basis Cost of Emissions Control Eq uipment Including Installation NOx Control Equipment (oversized LN-REACH with pressure atomizers and modified OFA) $1,950,000 Post-Combustion NOx Control (FLGR) $17,400,000

Contingency $3,870,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $23,220,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $3,306,000 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $1,500 65 $ per MWh
82 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $13,400 Includes costs associated with reduced boiler efficiency Maintenance Costs $282,800 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $297,700

TOTAL ANNUAL COST Annualized Capital Cost $3,306,000 Annual Operating Cost $297,700 Total Annual Cost $3,603,700 Based on estimated LNR(P)+OFA+FGR+FLGR retrofit cost (S&L cost database). Includes purchased equipment costs for combustion controls, FLGR and auxiliary equipment including installation.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

57 Control Option: LN-REACH (steam atomizers) + Modified OFA + FLGR

Unit 5

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (oversized LN-REACH with steam atomizers and modified OFA) $4,950,000 Post-Combustion NOx Control (FLGR) $17,400,000

Contingency $4,470,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $26,820,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $3,818,600 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $1,500 65 $ per MWh
82 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $13,400 Includes costs associated with reduced boiler efficiency Maintenance Costs $282,800 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $297,700

TOTAL ANNUAL COST Annualized Capital Cost $3,818,600 Annual Operating Cost $297,700 Total Annual Cost $4,116,300 Based on estimated LNR(S)+OFA+FGR+FLGR retrofit cost (S&L cost database). Includes purchased equipment costs for combustion controls, FLGR and auxiliary equipment including installation.

Unit 6

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (oversized LN-REACH with steam atomizers and modified OFA) $4,950,000 Post-Combustion NOx Control (FLGR) $17,400,000

Contingency $4,470,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $26,820,000

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $3,818,600 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $1,500 65 $ per MWh
82 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $13,400 Includes costs associated with reduced boiler efficiency Maintenance Costs $282,800 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $297,700

TOTAL ANNUAL COST Annualized Capital Cost $3,818,600 Annual Operating Cost $297,700 Total Annual Cost $4,116,300 Based on estimated LNR(S)+OFA+FGR+FLGR retrofit cost (S&L cost database). Includes purchased equipment costs for combustion controls, FLGR and auxiliary equipment including installation.NRG Energy July 26, 2010 Oswego Generating Station Units 5 & 6 RACT/BART Engineering Study

FINAL REPORT

58 Control Option: Selective Catalytic Reduction (SCR)

Unit 5

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (combustion controls plus SCR and ammonia handling system) $87,000,000 Based on estimated SCR retrofit cost (S&L cost database). Includes SCR, initial catalyst, ammonia handling system, and installation.

Contingency $17,400,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $104,400,000 sum of direct capital costs, indi rect capital costs, and contingency

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $14,864,200 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $56,200 65 $ per MWh 3,084 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $206,600 Includes reagent costs Maintenance Costs $161,000 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $423,800

TOTAL ANNUAL COST Annualized Capital Cost $14,864,200 Annual Operating Cost $423,800 Total Annual Cost $15,288,000

Unit 6

CAPITAL COSTS [$] Basis Cost of Emissions Control Equipment Including Installation NOx Control Equipment (combustion controls plus SCR and ammonia handling system) $87,000,000 Based on estimated SCR retrofit cost (S&L cost database). Includes SCR, initial catalyst, ammonia handling system, and installation.

Contingency $17,400,000 20% of direct and indirect capital costs. Alternative Control Techniques Document, Table 6-1. Total Capital Requirement (TCR) $104,400,000 sum of direct capital costs, indirect capital costs, and contingency

Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.1424 10 life of equipment (years) Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $14,864,200 7% pretax marginal rate of return on private investment

OPERATING COSTS Basis

Operating & Maintenance Costs Annual O&M Costs are appropriate for unit capacity factors below approximatley 11% Electricty Costs @ Annual CF $56,200 65 $ per MWh 3,084 kW (control system auxiliary power requirement) Natural Gas Costs $0 Catalyst Replacement and/or Reactant Costs $206,600 Includes reagent costs Maintenance Costs $161,000 Includes labor, supervisory labor, administration and other fixed O&M Total O&M Costs $423,800

TOTAL ANNUAL COST Annualized Capital Cost $14,864,200 Annual Operating Cost $423,800 Total Annual Cost $15,288,000NRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT59Oswego Unit 5NOx Control Cost-Effectiveness SummaryOptionControl Technology EmissionsTons of NOxRemovedAnnual CapitalRecovery CostTotal AnnualOperating CostsTotal AnnualCostsAverage CostEffectiveness(tpy) (tpy) ($) ($/kW-gross) ($/year) ($/year) ($) ($/ton)BaseBaseline Boiler Emissions242.1Option 1Neural Network (NN)231.1 11.0 $1,200,000 $1.4 $170,900 $300,000 $470,900$42,809Option 2LNREACH (pressure atomizers) +modified OFA198.1 44.0 $2,340,000 $2.8 $333,200 $51,700 $384,900$8,748Option 3LNREACH (steam atomizers) +modified OFA187.1 55.0 $5,940,000 $7.0 $845,700 $54,800 $900,500$16,373Option 4LNREACH (pressure atomizers) +modified OFA + SNCR154.1 88.0 $9,600,000 $11.3 $1,366,800 $317,600 $1,684,400$19,141Option 5LNREACH (pressure atomizers) +modified OFA + FLGR143.1 99.0 $23,220,000 $27.3 $3,306,000 $297,700 $3,603,700$36,401Option 6LNREACH (steam atomizers) + modifiedOFA + SNCR143.1 99.0 $13,200,000 $15.5 $1,879,400 $317,800 $2,197,200$22,194Option 7LNREACH (steam atomizers) + modifiedOFA + FLGR132.1 110.0 $26,820,000 $31.6 $3,818,600 $297,700 $4,116,300$37,421Option 8SCR33.0 209.1 $104,400,000 $122.8 $14,864,200 $423,800 $15,288,000$73,113Total Capital InvestmentNRG EnergyJuly 26, 2010Oswego Generating StationUnits 5 & 6 RACT/BART Engineering StudyFINAL REPORT60Oswego Unit 6NOx Control Cost-Effectiveness SummaryOptionControl Technology EmissionsTons of NOxRemovedAnnual CapitalRecovery CostTotal AnnualOperating CostsTotal AnnualCostsAverage CostEffectiveness(tpy) (tpy) ($) ($/kW-gross) ($/year) ($/year) ($) ($/ton)BaseBaseline Boiler Emissions210.1Option 1Neural Network (NN)199.1 11.0 $1,200,000 $1.4 $170,900 $300,000 $470,900$42,809Option 2LNREACH (pressure atomizers) +modified OFA188.0 22.1 $2,340,000 $2.8 $333,200 $51,700 $384,900$17,416Option 3LNREACH (steam atomizers) +modified OFA177.0 33.1 $5,940,000 $7.0 $845,700 $54,800 $900,500$27,205Option 4LNREACH (pressure atomizers) +modified OFA + SNCR154.8 55.3 $9,600,000 $11.3 $1,366,800 $317,600 $1,684,400$30,459Option 5LNREACH (pressure atomizers) +modified OFA + FLGR143.8 66.3 $23,220,000 $27.3 $3,306,000 $297,700 $3,603,700$54,354Option 6LNREACH (steam atomizers) + modifiedOFA + SNCR143.8 66.3 $13,200,000 $15.5 $1,879,400 $317,800 $2,197,200$33,140Option 7LNREACH (steam atomizers) + modifiedOFA + FLGR132.7 77.4 $26,820,000 $31.6 $3,818,600 $297,700 $4,116,300$53,182Option 8SCR33.2 176.9 $104,400,000 $122.8 $14,864,200 $423,800 $15,288,000$86,422Total Capital Investment