# nrg~~: CEC 3 to.; 

## I

Mr. Reginald Parker RAPCE Region 7 New York State Department of Environmental Conservation 615 Erie Boulevard West Syracuse, NY 13204-2400 REFERENCE: NOx RACT NYSDEC Subpart 227-2 Dear Mr. Parker: NRG EnergyInc. Oswego HarborPower 261 WashingtonBlvd Oswego, NY 13126

December29,2011

In accordance with NYSDEC Subpart 227-2.3 (b) attached is the NRG NOx RACT Compliance Plan for Oswego Harbor Power LLC.

Ifyou have any question please don't hesitate to call me at (315) 529-6710.

Thomas F. Coates Regional Environmental Manager

cc: NYSDEC Division ofAir Resources 

### R. Marko M. Greenhalgh

# NRG Energy, 

# Inc. Oswego NOx RACT



# CompliancePlan
Submittedtothe NewYorkState DepartmentofEnvironmental Conservation
December2011
This PlanCovers the NRG Oswego Station

# NRG EnergyInc. NOxRACT CompliancePlanSummary

• This plan addresses the methods by which the Oswego station will achieve and maintain NOx RACT compliance in accordance with 6NYCRR Part 227.

• The applicable presumptive NOx RACT limit in section 227-2.4 is not economically or technically feasible at Units 5, 6, 9 and 10 so NRG requests that the Department set the following higheremission source specific emission limit:

• For Unit 5

• For Unit 6

• For Unit 9

• For Unit 10

• As specified in Part 227-2.5(c), NRG has demonstrated that Units 5, 6, 9 and 10 do not meet the economic or technical feasibility requirements through an analysis that includes, the evaluation of the use of fuel switching, the use of a system averaging plan, and implementation of any available control technologies (including, for example, selective catalytic reduction).

December 2011 Page 1 of 14

# Contentsofthis Plan

Section 1: DescriptionofAffected Facilities

• Location

• Size andtype

• Fuel combusted

• Permitstatus

• Primaryfacility contacts

• NOxCompliancecontacts

• Responsible officialforeachfacility Section2: NOx

# RACTApplicability, CurrentStatus andProposed Alternative Rate Limits Section 3: NOx

# RACT EconomicandTechnical Feasibility

• Units 5and 6BARTFeasibilityAnalysis o 

# Baseline Emissions 

# o ControlAnalysis o 

# Annual Restriction

• Unit9 NOx RACTFeasibilityAnalysis

• Unit 10NOx RACT FeasibilityAnalysis

December 2011 Page 2 of 14

## Section 1 DescriptionofOswego Station
The Oswego Station has five boilers, three of which are classified as very large boilers and two that are classified as mid-size boilers. Unit 3 is rated at 1015 mmBtu/hr and primarilyfires natural gas. It currently has been placed in long-term cold storage and is not included in this plan. Units 5 and 6 are both rated at 9016 mmBtu/hr and fire residual oil. Both of these units are equipped with gas igniters. Unit 6 has a limited natural gas firing capacity and can generate up to approximately 180 MW when firing natural gas. Unit 5 cannot operate on natural gas. Actual NOx emission rates from Units 5 and 6 when firing residual oil are lower than the NOx RACT limits of 0.25 Ibs. NOx/mmBtu found in Part 227-2.4(a)(1). If Unit 6 isfiring natural gas only, the allowable emission rate is 0.20 Ibs. NOx/mmBtu.
If Unit 6 is co-firing gas and oil, the allowable NOx emission rate (NSPS limit) is pro-rated between 0.20 and 0.30 Ibs. NOx/mmBtu, based on the heat input. If the pro-rated emission rate is lessthan 0.25 lb. NOx/mmBtu, SNRCs are generated.
Unit 9 is a mid-size boiler (75 mmBtu/hr) capable of firing natural gas, distillate, or residual oil and has actual emissions of0.135 Ibs. NOx/mmBtu. Unit 9 is not operated if any ofthe otherthree boilers are in operation.
Unit 10 is a mid-size boiler (nominal 90.5 mmBtu/hr) capable of firing natural gas and distillate. The unit has not fired distillate fuel. The unit is equipped with low NOx burners and the as tested NOx emissions on natural gas are less than or equal to 0.10 Ibs/mmBtu. This unit is not included in the system-wide average plan.
The Primary Facility Contact is Ms. Marion L. Greenhalgh. The NOx Compliance Contact is Mr. Thomas F. Coates. The Responsible Official is Mr. Robert Marko. 315-349-2365 315-349-2231 315-349-2677 South Oswego Oil Terminal
The South Oswego Oil Terminal has submitted aTitle VAir permit application that limits NOx emissions from the combustion sources at the terminal to less than 100tons/year. As a result of this cap, the combustion sources are excluded from Part 227-2 requirements.

December 2011 Page 3of 14

## Section2 NOxRACTApplicabilityandCurrentStatus
NRG Oswego Harbor Power hasfour boilersthat are subjectto the NOx RACT regulations. All four units were included in the NRG Upstate NY NOx RACT system averaging plan butthere is insufficient margin available in that averaging plan from Dunkirk and Huntleyto continue that compliance methodology. NRG proposes alternative NOx RACT limits for rates Unit 5 (0.25 Ibs. NOx per mmBtu); Unit 6 (0.22 Ibs. NOx per mmBtu); Unit 9 (0.135 Ibs. NOx per mmBtu; and Unit 10 (0.10 Ibs. NOx per mmBtu because it is nottechnologically and economically possible to meetthe presumptive limits in Part 227-2. The cost effectiveness analysis is presented in Section 

### 3.
Units 5 and 6 Proposed Alternative NOx RACT Limits The following methodologywas used to determine the proposed limits for Units 5 and 6. HourlyCEMS data in the period 1/1/2006to 12/31/2010for all hours when there was a positive load value was combined in asingle data setfor each unit. Note that in this analysis hourly data from operating periods separated by periods when the units were not operating were used to calculate the 24-hour blocks. In addition, the I.ast 23 hours with positive load values from 2005 were added to the averaging periods so that every hourwith load from 1/1/2006 had avalid 24-hourvalue. Part §227-2.6 (b)(3)(i)(b) states: "demonstrate compliance with the appropriate emission limit undersection 227- 2.4 ofthis Subpart by using aCEMS for measuring NOxand calculating a24-hourdaily heat input-weighted average NOxemission rate". In this analysisthe 24-hour heat input weighted averages were calculated by dividing the sum of24- hour NOX mass calculated using rate and heat input bythe sum of24-hour heat input sothe method is compatible with the rule.
The results ofthis analysis are summarized in Table 1. Oswego 5 had 990 averages available (2.3% ofthe possible) and Oswego 6 had 849 averages or 1.9% ofthe possible. Oswego 5 has a higher average emission rate, likely because Oswego 5 has atendency to run more at higher loads which have higher emission rates. Neither rate is close to the Presumptive NOX RACT limit of0.15. The standard deviations are both relatively small. The distribution ofobserved values ranges from 0.07 to 0.27 for Oswego 5 and 0.11 to 0.24for Oswego 6.

December 2011 Page 4 of 14Table 1: SummaryofOswego 24-hour heat input weighted average NOx emission rates 24-Hour Running Oswego 5 Oswego 6 Count 990 849 Average 0.21 0.18 Standard deviation 0.03 0.03 Mean + 1 Std. Dev. 0.24 0.21 Mean +2 Std. Dev. 0.27 0.24 Minimum 0.07 0.11 1% Percentile 0.09 0.11 5% Percentile 0.16 0.13 10% Percentile 0.17 0.14 25% Percentile 0.18 0.16 50% Percentile 0.21 0.18 75% Percentile 0.23 0.21 90% Percentile 0.24 0.22 95% Percentile 0.25 0.22 99% Percentile 0.27 0.23 Maximum 0.27 0.24

Part 227 does not specify a methodologyto determine the alternative NOx RACT emission rate. In orderto incorporate expected variability itwould be reasonable to proposethe mean plus one standard deviation orthe 95th percentile asthe alternative NOx RACT rate. Because compliance is determined on adaily block average basis it is appropriate to determine whetherthese two alternatives would have caused exceedances to the dailyaverages. Table 2 presents the results when the two potential alternative rates are compared to those 24-hour running averagesthat ended on the last hour ofthe day. Keep in mind thatthis does not insurethatthe dailyaverage represents only contiguous hours when the unitwas on-line. There were 43 and 35 "daily" averages at Oswego 5 and 6 respectively. At both units the mean plus one standard deviation alternative rate would have resulted in one exceedance. Therefore, NRG recommends usingthe 95th percentile rates of0.25 at Oswego 5 and 0.22 at Oswego 6 because there would not have been any exceedances.

December 2011 Page 5 of 14Table 2: Daily Oswego 24-hour heat inputweighted average NOxemission rates compared to alternative NOx RACT rates. Daily Oswego 5 Oswego 6 Count 43 35 Mean 

### + 1 Standard Deviation 0.24 0.21 Exceedances 1 1 95% percentile 0.25 0.22 Exceedances 0 0 NRG has developed a monitoring and reporting system which is capable of monitoring and recording the 24-hour and 3D-day NOx rates necessary. These systems meet the requirements of40 CFR Part 75 compliance as well as 6 NYCRR Part 227.

,.----.- Unit 9 Proposed Alternative Emission Rate Unit 9 is a mid-size boiler (75 mmBtu/hr) capable offiring natural gas, distillate, or residual oil and has actual emissions of0.135 Ibs. NOx/mmBtu.
Unit 10 Proposed Alternative Emission Rate Unit 10 is a mid-size boiler (nominal 90.5 mmBtu/hr) capable of firing natural gas and distillate and has actual emissions of0.1Ibs. NOx/mmBtu.

December 2011 Page 6of 14

## Section3 NOxRACTEconomicandTechnicalFeasibility
Units 5 and 6 The NOx RACTtechnology and economic analysisforthese units is based on the analysis completed for 6 NYCRR Part 249, BestAvailable RetrofitTechnology (BART) lastyear. Sources eligible for BART included Oswego Units 5 and 6and NRG did an analysis of retrofit control optionsfor each visibility-impairing pollutant required by Part 249 that included NOx. Available retrofit technologies were identified, the feasibility of installing the differenttechnologies was determined, and an evaluation ofthe technicallyfeasible alternatives was performed. Finally an impacts analysis was done to determine ifthere were anytechnologies that metthe DEC's cost effectivenessthreshold of$5,500 per ton. Itwas shown thatthere were no technical or economic alternativesfor NOxso pursuantto Part 227-4 NRG is requesting an alternative higher emission source specific emission limit.
Baseline Emissions The Oswego units have low annual emissions. Table 3 liststhe maximum 12 month emissions overthe period 1/1/2006to 12/31/2010for athree-year and five-year look back. Because there has been asignificant change in the price ofoil versus natural gas, operations at Oswego have dropped substantially in the pastfouryears. NRG proposed athree-year baseline for NOx in the BART analysisto accountforthose changes. Table 4 lists historical annual emissionsforthe lastten years. It is not expected that the operations atthese units will vary much from the levels ofthe last several years in the future. However, as noted in Appendix Yto Part 51-Guidelines for BART Determinations underthe Regional Haze Rule, ifthe projection forfuture operating parameters projection has adeciding effect in the BARTdetermination, then NRG must make these parameters orassumptions into enforceable limitations. As a result, this analysis determinesthe emission level consistent with $5,500 DEC cost effectiveness threshold for each parameterat each BART-eligible unit. Those values will be used to setthe future enforceable limits for NOx RACT as well as BART.
Table 3: Maximum Emissions for 3-Yearand 5-Year Look Back Periods BART Submittal NOX RACT Submittal Oswego Oswego Oswego Oswego Station Unit 5 Unit 6 Unit 5 Unit 6 3-Yr Maximum 12-month NOX Mass 243 107 213 107 3-Yr Maximum 12-month Heat Input 2,201,269 1,155,665 1,888,902 1,103,267 5-Yr Maximum 12-month NOX Mass 5-Yr Maximum 12-month Heat In ut

December 2011 748 476 732 476 6,878,855 4,791,637 6,730,639 4,791,637

Page 7of 14**swe~** 

### a mt Operating Gross load 502 NOx Rate NOx CO2 Heat Input Year Time (MWh) Tons (Ib/mmBtu) Tons Tons (mmBtu) 2001 1,159 338,433 2,103.9 0.19 400.3 312,674.3 3,863,027 2002 950 304,488 1,746.1 0.16 340.0 265,032.2 3,274,417 2003 577 197,419 1,087.5 0.16 224.1 171,726.4 2,121,648 2004 688 312,086 1,834.2 0.17 359.5 281,080.3 3,472,697 2005 1,463 621,802 3,822.4 0.17 732.2 544,776.5 6,730,639 2006 339 65,824 402.5 0.13 80.4 64,180.6 792,933 2007 493 167,334 1,125.5 0.15 213.1 152,888.4 1,888,902 2008 275 46,353 341.8 0.13 56.4 48,870.2 603,777 2009 218 28,505 192.6 0.10 35.0 29,577.7 365,434 2010 248 34,374 226.1 0.11 48.7 35,619.5 440,072 Table 4: EPA Clean Air Markets Division Annual Emissions Summary Data http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=iss.isshome



## o U'S

Oswego Unit 6 Operating Gross load 502 NOx Rate NOx CO2 Heat Input Year Time (MWh) Tons (lb/mmBtu) Tons Tons (mmBtu) 2001 928 234,933 893.4 0.16 253.0 209,358.1 2,601,898 2002 592 183,255 723.6 0.15 195.9 174,569.3 2,188,678 2003 576 219,585 812.4 0.17 259.5 191,045.3 2,367,434 2004 360 115,281 444.5 0.13 124.2 101,577.8 1,264,200 2005 1,072 451,668 1,703.4 0.16 470.6 381,640.9 4,728,518 2006 367 68,603 272.0 0.11 74.4 68,119.7 853,088 2007 342 91,381 349.3 0.13 102.8 84,123.0 1,051,367 2008 244 33,862 177.4 0.11 49.1 45,472.2 570,231 2009 229 50,827 188.0 0.12 53.3 47,276.1 589,691 2010 209 34,921 135.5 0.10 39.9 34,042.4 426,289 Oswego 5 and 6 NOx Control Analysis NRG contracted Sargent 

### & Lundy LLC ofChicago, Illinoisto evaluate technologies to be considered in the NOxcontrol technology analysisfor BART and RACTas described in the attached document. The Sargent 

### &Lundy analysis included asite visit; a review of existing operational data, boiler drawings, and emissions; an evaluation ofthe feasibility and effectiveness of potentially available combustion controls/modifications including burner modifications, over-fired air, natural gas re-burn, burners out ofservice, and flue gas re-circulation; an evaluation ofthe technical feasibility and effectiveness of SNCR/SCR control systems; and developed budgetary cost estimatesforthe technically feasible control technologies (budgetary $/kW costs based on industryaverages.)
The executive summaryofthe report states: This engineering reportwas prepared to supportthe Oswego Unit 5 

### & 6 RACT compliance evaluation and BARTdetermination, focusing on the control of NOx emissionsfrom both units. This evaluation follows the BARTdetermination process described the Appendix YGuidelines, and includesthe information and

December 2011 Page 8 of 14evaluations required by Steps 1 through 4 ofthe BARTdetermination process. The report reviews baseline NOx emissionsfrom each unit, identifies and evaluatesthe technical feasibility of potential NOx retrofit control options, and provides budgetary cost estimates and calculatesthe cost-effectiveness ofeach technicallyfeasible NOxcontrol technology. Tables ES-1 and ES-2 provide a summary ofthe technicallyfeasible NOx control options, including: (1) annual emission 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 cost-effectiveness ofeach technology.
Based on the evaluation ofcapital costs, operating costs, and annual emission reductions included herein, none ofthe technicallyfeasible and available NOx control options are cost effective on Oswego Units 5 

### & 6. Several site-specific factors 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 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/KW-gross (with steam atomization).
More importantly, baseline annual NOx emissions from both units are only in the range ofapproximately 240tpy. Baseline annual NOx emissions are low because ofthe low capacityfactors achieved by both units during the baseline period. Both units have had capacityfactors of 3.2% or less during the baseline period, and, in fact, neither unit has had acapacityfactor above 10% since 2001. Finally, both units are currently equipped with 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 Ib/mmBtu and 0.19 Ib/mmBtu, respectively). Low baseline NOx emission rates, coupled with the low unit capacityfactors, result in baseline annual NOx emissions ofonly about 240 tpyfrom each units. The low baseline NOx emission rates contribute significantly tothe high cost-effectiveness of potential retrofit NOxcontrol technologies. Assuming the units continue to operate at low capacityfactors, none ofthe potential NOx control systems, including combustion modifications, would be cost effective. Sargent and Lundy used the actual emission rate achieved during the baseline period (0.22 Ib/mmBtu for Unit 5 and 0.19 Ib/mmBtu for Unit 6) and an annual capacityfactor

December 2011**-----~** --_._-._- Page 9 of 14of 3.2% (the highest 12-month capacityfactor achieved by either unit during the baseline period) to calculate unit-specific baseline annual emissions. Projected emissionsfor each NOx control scenario were estimated using an emission rate achievable with each technology, and (when appropriate) taking into consideration how the boilers are currentlyfired. Forthose control scenariosthat included FLGR, SNCR, and SCR Sargent and Lundy used the same controlled emission rate for both units because ofthe significant changes needed to each boiler's combustion control systems. Forthe control options that only included changes tothe LN-REACH and OFA control systems, Sargent and Lundytook into consideration howthe boilers are currentlyfired. Note that control efficiency is not constant, but is afunction ofthe baseline emission rate.
Because the BART analysis is supposed to be unit-specific, Sargent and Lundy calculated unit-specific cost effectiveness estimates. The budgetary cost estimates prepared for the various control options were the same for both units becausethe boilers arethe same size and have similarflue gasflow rates, temperatures, residence times, etc. However, becausethe baseline emissions and removal efficiencies are different, the cost-effectiveness values will be differentforthe two units. In general, controls will be less cost-effective on Unit 6 because ofthe lower baseline rate.
Annual Restriction In orderto determine the appropriate permit restriction the annual tonnage limit below which there are no NOxcontrol technologies available that has cost-effectiveness less than the DEC'sthreshold of$5,500 perton hasto be calculated (Table 5). As the annual capacityfactor increases, the variable O&M costs increase, sototal annual costs are not constant, but are afunction ofthe capacityfactor. Sargent and Lundy determined the capacityfactorforthe cost-effectiveness $5,500/ton threshold accountingforthe annual O&M costs and capital costs by checking different capacityfactors. On Unit 5, Option 2 (LN-REACH (pressurized atomizers) and modified OFA) crosses the $5,500/ton threshold at an annual capacityfactor ofapproximately 5.1% (3,496,657 mmBtu/yror baseline NOx rate of383 tons peryear) as shown in Table 5.

December 2011 Page 10 of 14Table 5: Sargent and Lundy Option 2 Cost Effectiveness as a Function ofCapacity Factorfor Oswego Unit 5and Unit 6
Unit 5 0.22 0.18 Capacity Annual Baseline Projected Tons Total Cost

Factor Heat Input Emissions Emissions Removed Annual Cost Effectiveness

(%) (mmBtu) (tpy) (tpy) (tpy) ($jyr) ($jton) 3.0% 2,056,857 226.3 185.1 41.2 $384,900 $9,342 4.9% 3,359,534 369.5 302.4 67.1 $384,900 $5,736 5.0% 3,428,095 377.1 308.5 68.6 $384,900 $5,611 5.1% 3,496,657 384.6 314.7 70.0 $384,900 $5,503 5.2% 3,565,219 392.2 320.9 71.3 $384,900 $5,398 5.3% 3,633,781 399.7 327.0 72.7 $384,900 $5,294 6.0% 4,113,715 452.5 370.2 82.3 $384,900 $4,677
Unit 6 0.19 0.17 "- Capacity Annual Baseline Projected Tons Total Cost

Factor Heat Input Emissions Emissions Removed Annual Cost Effectiveness

(%) (mmBtu) '(tpy) (tpy) (tpy) ($jyr) ($jton) 6.0% 4,122,871 391.7 350.4 41.3 $384,900 $9,320 10.0% 6,871,452 652.8 584.1 68.7 $384,900 $5,603 10.1% 6,940,166 659.3 589.9 69.4 $384,900 $5,546 10.2% 7,008,881 665.8 595.8 70.0 $384,900 $5,499 10.3% 7,077,595 672.4 601.6 70.8 $384,900 $5,436 12.0% 

### 8,245J42 783.3 700.9 82.4 $384,900 $4,671
On Unit 6, Option 2 crosses the $5,500jton threshold at acapacityfactor of approximately 10.2% (7,008,881 mmBtujyr or baseline NOx rate of666 tons peryear) as shown in Table 5. NRG has proposed to incorporate an annual NOx mass limit in its Title V permitsfor Oswego Units 5 and 6. Sargent and Lundy determined the unit-specific annual tonnage limitbeTOwwhich there are no NOx control technologies available that has costeffectiveness lessthan the DEC's threshold of$5,500 perton was 383 tons for Unit 5 and 666 tons for Unit 6. In orderto address the baseline artifact issue, the permit could include astation trigger of 1,049tons (the sum of both unit caps) or simplytake the average ofthe sum ofthe totals and establish unittriggers of524tons peryear. Unit 9 Unit 9 is used as abackup auxiliary steam boiler. As a result it runs very infrequently and has a baseline emission rate of2tons. NRG had Indeck Keystone Energy, LLCfrom Erie, PA evaluate NOx control optionsforthe boiler. The preliminary and approximate budget price forthe replacement burner system, IFGR ductwork, new FD Fan, burner

December 2011 Page 11 of 14management system, and combustion control system forthe #13M Keystone Steam Generator (Zurn) is $850,000. Predicted emissions, when firing natural gas, would be 0.05 Ibs. per mmBtu NOxcorrected to flue gas oxygen of3%, dry basis. In addition, the pricing isforthe fabricated parts only and does not include field labororsupervision costs, casings or insulation or shipping costs. The cost ofthe equipment alone ($850,000) putsthe cost ofcontrols perton reduced ($88,845 perton) overthe cost effectivenessthreshold of$5,500 perton (Table 6)

Unit 10 Unit 10 is used as the primary auxiliary steam boiler. Because Units 5 and 6 run very infrequently it is necessaryto run this boiler more than Unit 9 butthe baseline emissions are still only 18.1 tons. NRG had Indeck Keystone Energy, LLCfrom Erie, PA evaluate NOx control options forthe boiler. The preliminaryand approximate budget price forthe replacement burnersystem, IFGR ductwork, new FD Fan, burner management system, and combustion control system forthe D3-70Volcano DType Steam Generator is $850,000. Predicted emissions, when firing natural gas, would be 0.05 Ibs. per mmBtu NOx corrected to flue gas oxygen of3%, dry basis. In addition, the pricing is forthe fabricated parts only and does not include field laboror supervision costs, casings or insulation or shipping costs. The cost ofthe equipment alone ($850,000) puts the cost ofcontrols perton reduced ($12,362 perton) overthe cost effectiveness threshold of$5,500 perton (Table 7)

December 2011 Page 12 of 14Table 7: DECAir Guide 20 EconomicAnalysis
-Air Emissions Control Equipmentfor Oswego 9

Facility Name
Facility ID Emission Point Control Type NRG Oswego Harbor Power 261 Washinqton Blvd Osweqo, NY 13126 Oswego 9 

## I LNB 

## I
Cost of Emissions Control Equipment including installation Calculate Capital Recovery Factor 1= Annual interest rate n= Equipment or replacement parts life in years (n=10) 

## I $ 850,000
0.130 5%

10 Calculate Annual Equipment Cost (Multiply Item 1 by Item 2 Annual Operating Costs Electricity Natural gas Catalyst replacement Carbon replacement Maintenance $ 110,078.89 $ 1,800 $



### - $

- $

- $



### - Rate Hours $ 1,800 $ 150 I 12 

## I
Total Annual Costs (Add items 3and 4[Ato e]) 

## I $ 111,879 Calculate Annual VOC or NOXTonnage Reduction VOC or NOX actual annual emissions Percent capture and control achieved Tons reduced (multiply item 6A by 6B) Total Cost ofControls perTon Reduced (Divide Item 5 by Item 6C)

December 2011 2.0 Existinq Limit 63% 0.135 

## I 0.05 

## I

1.3
88,845.00

Page 13 of 

### 14Table 8: DEC Air Guide 20 Economic Analysis - Air Emissions Control Equipment for Oswego 10

Facility Name
Facility ID Emission Point Control Type NRG Osweqo Harbor Power 261 Washinqton Blvd Osweao, NY 13126 Osweao 10 

## I LNB 

## I
Cost of Emissions Control Equipment including installation Calculate Capital Recovery Factor 1= Annual interest rate n= Equipment or replacement parts life in years (n=10) 

## I $ 850,000
0.130 5%

10 Calculate Annual Equipment Cost (Multiply Item 1 by Item 2 Annual Operating Costs Electricity Natural gas Catalyst replacement Carbon replacement Maintenance $ 110,078.89 $ 1,800 $



### - $



### - $



### - $



### - Rate Hours $ 1,800 $ 150 

## I 12 

## I
Total Annual Costs (Add items 3 and 4[Ato e]) 

## I $ 111,879 Calculate Annual VOC or NOXTonnage Reduction VOC or NOX actual annual emissions Percent capture and control achieved Tons reduced (multiply item 6A by 6B) Total Cost of Controls perTon Reduced (Divide Item 5 by Item 6C)

December 2011 18.1 Existing Limit 50% 0.1 

## I 0.05 

## I

9.1
12,362.31

Page 

### 14 of 

### 14