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 Energy Inc.

Oswego Harbor Power

261 Washington Blvd

Oswego, NY 13126

December 29,2011

In accordance with NYSDEC Subpart 227-2.3 (b) attached is the NRG NOx

RACT Compliance Plan for Oswego Harbor Power LLC.

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

Thomas F. Coates

Regional Environmental Manager

cc: NYSDEC Division of Air Resources

R. Marko

M. Greenhalgh
NRG Energy, Inc.

Oswego NOx RACT

Compliance Plan

Submitted to the New York State

Department of Environmental

Conservation

December 2011

This Plan Covers the NRG Oswego Station
NRG Energy Inc.

NOx RACT Compliance Plan Summary

• 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

higher emission 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
Contents ofthis Plan

Section 1: Description ofAffected Facilities

• Location

• Size and type

• Fuel combusted

• Permit status

• Primary facility contacts

• NOx Compliance contacts

• Responsible official for each facility

Section 2: NOx RACT Applicability, Current Status and Proposed

Alternative Rate Limits

Section 3: NOx RACT Economic and Technical Feasibility

• Units 5 and 6 BART Feasibility Analysis

o Baseline Emissions

o Control Analysis

o Annual Restriction

• Unit 9 NOx RACT Feasibility Analysis

• Unit 10 NOx RACT Feasibility Analysis

December 2011 Page 2 of 14
Section 1 Description of Oswego 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

primarily fires 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 is firing 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 less than 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 of 0.135 Ibs. NOx/mmBtu. Unit 9 is not operated if

any of the other three 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 a Title V Air permit application that limits

NOx emissions from the combustion sources at the terminal to less than 100 tons/year.

As a result of this cap, the combustion sources are excluded from Part 227-2

requirements.

December 2011 Page 3 of 14
Section 2 NOx RACT Applicability and Current Status

NRG Oswego Harbor Power has four boilers that are subject to the NOx RACT

regulations. All four units were included in the NRG Upstate NY NOx RACT system

averaging plan but there is insufficient margin available in that averaging plan from

Dunkirk and Huntley to 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 not technologically and economically possible to meet the

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 methodology was used to determine the proposed limits for Units 5 and

6. Hourly CEMS data in the period 1/1/2006 to 12/31/2010 for all hours when there was

a positive load value was combined in a single data set for 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

hour with load from 1/1/2006 had a valid 24-hour value. Part §227-2.6 (b)(3)(i)(b)

states: "demonstrate compliance with the appropriate emission limit under section 227-

2.4 of this Subpart by using a CEMS for measuring NOx and calculating a 24-hour daily

heat input-weighted average NOx emission rate". In this analysis the 24-hour heat input

weighted averages were calculated by dividing the sum of 24- hour NOX mass calculated

using rate and heat input by the sum of 24-hour heat input so the method is compatible

with the rule.

The results of this analysis are summarized in Table 1. Oswego 5 had 990 averages

available (2.3% of the possible) and Oswego 6 had 849 averages or 1.9% of the possible.

Oswego 5 has a higher average emission rate, likely because Oswego 5 has a tendency

to run more at higher loads which have higher emission rates. Neither rate is close to

the Presumptive NOX RACT limit of 0.15. The standard deviations are both relatively

small. The distribution of observed values ranges from 0.07 to 0.27 for Oswego 5 and

0.11 to 0.24 for Oswego 6.

December 2011 Page 4 of 14
Table 1: Summary of Oswego 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 methodology to determine the alternative NOx RACT

emission rate. In order to incorporate expected variability it would be reasonable to

propose the mean plus one standard deviation or the 95th percentile as the alternative

NOx RACT rate. Because compliance is determined on a daily block average basis it is

appropriate to determine whether these two alternatives would have caused

exceedances to the daily averages. Table 2 presents the results when the two potential

alternative rates are compared to those 24-hour running averages that ended on the

last hour of the day. Keep in mind that this does not insure that the daily average

represents only contiguous hours when the unit was 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 using the 95th percentile rates of 0.25 at Oswego 5 and 0.22 at

Oswego 6 because there would not have been any exceedances.

December 2011 Page 5 of 14
Table 2: Daily Oswego 24-hour heat input weighted average NOx emission 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 of 40 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 of firing natural gas, distillate, or

residual oil and has actual emissions of 0.135 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 of 0.1Ibs. NOx/mmBtu.

December 2011 Page 6 of 14
Section 3 NOx RACT Economic and Technical Feasibility

Units 5 and 6

The NOx RACT technology and economic analysis for these units is based on the analysis

completed for 6 NYCRR Part 249, Best Available Retrofit Technology (BART) last year.

Sources eligible for BART included Oswego Units 5 and 6 and NRG did an analysis of

retrofit control options for each visibility-impairing pollutant required by Part 249 that

included NOx. Available retrofit technologies were identified, the feasibility of installing

the different technologies was determined, and an evaluation of the technically feasible

alternatives was performed. Finally an impacts analysis was done to determine if there

were any technologies that met the DEC's cost effectiveness threshold of $5,500 per

ton. It was shown that there were no technical or economic alternatives for NOx so

pursuant to 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 lists the maximum 12 month

emissions over the period 1/1/2006 to 12/31/2010 for a three-year and five-year look

back. Because there has been a significant change in the price of oil versus natural gas,

operations at Oswego have dropped substantially in the past four years. NRG proposed

a three-year baseline for NOx in the BART analysis to account for those changes. Table 4

lists historical annual emissions for the last ten years. It is not expected that the

operations at these units will vary much from the levels of the last several years in the

future. However, as noted in Appendix Yto Part 51-Guidelines for BART

Determinations under the Regional Haze Rule, if the projection for future operating

parameters projection has a deciding effect in the BART determination, then NRG must

make these parameters or assumptions into enforceable limitations. As a result, this

analysis determines the emission level consistent with $5,500 DEC cost effectiveness

threshold for each parameter at each BART-eligible unit. Those values will be used to

set the future enforceable limits for NOx RACT as well as BART.

Table 3: Maximum Emissions for 3-Year and 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 7 of 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 of Chicago, Illinois to evaluate technologies to be

considered in the NOx control technology analysis for BART and RACT as described in

the attached document. The Sargent & Lundy analysis included a site visit; a review of

existing operational data, boiler drawings, and emissions; an evaluation of the feasibility

and effectiveness of potentially available combustion controls/modifications including

burner modifications, over-fired air, natural gas re-burn, burners out of service, and flue

gas re-circulation; an evaluation of the technical feasibility and effectiveness of

SNCR/SCR control systems; and developed budgetary cost estimates for the technically

feasible control technologies (budgetary $/kW costs based on industry averages.)

The executive summary ofthe report states:

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 determination

process described the Appendix YGuidelines, and includes the information and

December 2011 Page 8 of 14
evaluations required by Steps 1 through 4 of the BART determination process.

The report reviews baseline NOx emissions from each unit, identifies and

evaluates the technical feasibility of potential NOx retrofit control options, and

provides budgetary cost estimates and calculates the cost-effectiveness of each

technically feasible NOx control technology. Tables ES-1 and ES-2 provide a

summary of the technically feasible 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 of each

technology.

Based on the evaluation of capital costs, operating costs, and annual emission

reductions included herein, none of the technically feasible 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 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 with low-NOx combustion controls,

including LNREACH, over fire 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 capacity factors, result in baseline annual NOx emissions of only about 240

tpy from each units. The low baseline NOx emission 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.

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 capacity factor

December 2011

-----~ --.-.-

Page 9 of 14
of 3.2% (the highest 12-month capacity factor achieved by either unit during the

baseline period) to calculate unit-specific baseline annual emissions. Projected

emissions for each NOx control scenario were estimated using an emission rate

achievable with each technology, and (when appropriate) taking into consideration how

the boilers are currently fired. For those control scenarios that included FLGR, SNCR,

and SCR Sargent and Lundy used the same controlled emission rate for both units

because of the significant changes needed to each boiler's combustion control systems.

For the control options that only included changes to the LN-REACH and OFA control

systems, Sargent and Lundy took into consideration how the boilers are currently fired.

Note that control efficiency is not constant, but is a function of the 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 because the boilers are the

same size and have similar flue gas flow rates, temperatures, residence times, etc.

However, because the baseline emissions and removal efficiencies are different, the

cost-effectiveness values will be different for the two units. In general, controls will be

less cost-effective on Unit 6 because of the lower baseline rate.

Annual Restriction

In order to determine the appropriate permit restriction the annual tonnage limit below

which there are no NOx control technologies available that has cost-effectiveness less

than the DEC's threshold of $5,500 per ton has to be calculated (Table 5). As the annual

capacity factor increases, the variable O&M costs increase, so total annual costs are not

constant, but are a function of the capacity factor. Sargent and Lundy determined the

capacity factor for the cost-effectiveness $5,500/ton threshold accounting for the

annual O&M costs and capital costs by checking different capacity factors. On Unit 5,

Option 2 (LN-REACH (pressurized atomizers) and modified OFA) crosses the $5,500/ton

threshold at an annual capacity factor of approximately 5.1% (3,496,657 mmBtu/yr or

baseline NOx rate of 383 tons per year) as shown in Table 5.

December 2011 Page 10 of 14
Table 5: Sargent and Lundy Option 2 Cost Effectiveness as a Function of Capacity

Factor for Oswego Unit 5 and 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 a capacity factor of

approximately 10.2% (7,008,881 mmBtujyr or baseline NOx rate of 666 tons per year) as

shown in Table 5.

NRG has proposed to incorporate an annual NOx mass limit in its Title V permits for

Oswego Units 5 and 6. Sargent and Lundy determined the unit-specific annual tonnage

limit beTOwwhich there are no NOx control technologies available that has costeffectiveness less than the DEC's threshold of $5,500 per ton was 383 tons for Unit 5

and 666 tons for Unit 6. In order to address the baseline artifact issue, the permit could

include a station trigger of 1,049 tons (the sum of both unit caps) or simply take the

average of the sum of the totals and establish unit triggers of 524 tons per year.

Unit 9

Unit 9 is used as a backup auxiliary steam boiler. As a result it runs very infrequently

and has a baseline emission rate of 2 tons. NRG had Indeck Keystone Energy, LLC from

Erie, PA evaluate NOx control options for the boiler. The preliminary and approximate

budget price for the replacement burner system, IFGR ductwork, new FD Fan, burner

December 2011 Page 11 of 14
management system, and combustion control system for the #13M Keystone Steam

Generator (Zurn) is $850,000. Predicted emissions, when firing natural gas, would

be 0.05 Ibs. per mmBtu NOx corrected to flue gas oxygen of 3%, dry basis. In addition,

the pricing is for the fabricated parts only and does not include field labor or supervision

costs, casings or insulation or shipping costs. The cost of the equipment alone

($850,000) puts the cost of controls per ton reduced ($88,845 per ton) over the cost

effectiveness threshold of $5,500 per ton (Table 6)

Unit 10

Unit 10 is used as the primary auxiliary steam boiler. Because Units 5 and 6 run very

infrequently it is necessary to run this boiler more than Unit 9 but the baseline

emissions are still only 18.1 tons. NRG had Indeck Keystone Energy, LLC from Erie, PA

evaluate NOx control options for the boiler. The preliminary and approximate budget

price for the replacement burner system, IFGR ductwork, new FD Fan, burner

management system, and combustion control system for the D3-70 Volcano 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 of 3%, dry basis. In addition,

the pricing is for the fabricated parts only and does not include field labor or supervision

costs, casings or insulation or shipping costs. The cost of the equipment alone

($850,000) puts the cost of controls per ton reduced ($12,362 per ton) over the cost

effectiveness threshold of $5,500 per ton (Table 7)

December 2011 Page 12 of 14
Table 7: DEC Air Guide 20 Economic Analysis - Air Emissions Control Equipment for

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 3 and 4[A to e]) I $ 111,879

Calculate Annual VOC or NOX Tonnage Reduction

VOC or NOX actual annual emissions

Percent capture and control achieved

Tons reduced (multiply item 6A by 6B)

Total Cost of Controls per Ton 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 14
Table 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[A to e]) I $ 111,879

Calculate Annual VOC or NOX Tonnage Reduction

VOC or NOX actual annual emissions

Percent capture and control achieved

Tons reduced (multiply item 6A by 6B)

Total Cost of Controls per Ton 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