# Best Available Retrofit Technology (BART)

Analyses for

Arthur Kill Unit 30,

Oswego Unit 5 and

Oswego Unit 6

NRG Energy

Oswego, NY

August 4, 2010

### 2

### 1 Introduction

The New York State Department of Environmental Conservation adopted 6 NYCRR

P art 249, Best Available Retrofit Tech nology (BART) pursuant to Clean Air Act Section

169A and the federal Regional Haze Rule (July 1, 1999; 64 FR 35714) to reduce

regional haze in Federal Class I areas. Sources eligible for BART are those which

belong to o ne of 26 specific source categories, commenced operation or underwent

reconstruction between August 7, 1962 and August 7, 1977, and have the potential to

emit 250 t ons p er y ear or more of any of the visibility

- impairing pollutants: sulfur dioxide,

oxides o f nitrogen, and particulate matter less than 10 microns in size.

NRG Energy (NRG) owns and operates three units in New York that are eligible for

BART: Arthur Kill Unit 30, Oswego Unit 5 and Oswego Unit 6. Given that Arthur Kill

has only burned gas in t he last ten years and that the capacity factors at Oswego are

very low, NRG has not done a complete detailed five

- factor analysis for each unit and

each pollutant. DEC has noted:

"As long [as] these most stringent controls available are made federally

en forceable for the purpose of implementing BART for that source, you may skip

the remaining analyses in this section, including the visibility analysis in step 5.

[In other words, if the most stringent controls available are already in place, no

modeling is required.] Likewise, if a source commits to a BART determination

that consists of the most stringent controls available, then there is no need to

complete the remaining analyses in this section."

This report describes the analysis of retrofit control opt ions for each visibility

- impairing

pollutant required by Part 249

. Available retrofit technologies were identified for each

pollutant, the feasibility of installing the different technologies was determined, and an

evaluation of the technically feasible a lternatives 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.

NRG believes that this analysis is conservative particular ly in light of the lower cost

effective thresholds used in EPA’s recently released Clean Air Transport Rule . In their

analysis, EPA developed specific cost thresholds for annual SO2, annual NOX, and

ozone season NOX based on downwind air quality impacts. “In this proposal E PA

divides, for individual pollutants, the significantly contributing states into two groups:

those whose significant contribution can be eliminated at a lower cost threshold; and

those whose significant contribution is not eliminated (to the extent that i s has been

identified in this proposal) until they reach the higher cost threshold.” For SO2 impacts

on PM 2.5 EPA considered two cost thresholds: $2,000 and $2,400 per ton and

determined “that SO2 emissions that could be reduced for $2,000/ton in

2014 sh ould be considered a state’s significant contribution”. For NOx impacts on PM

2.5 EPA considered a low cost threshold so the Ozone Season NOx impacts are more

conservative. At page 319 of the proposed rule the EPA discussion notes that:

EPA believes that on purely reasonableness or highly cost effective grounds, a

value considerably greater than $500/ton could be justified. EPA notes that the

$2,000/ton threshold for highly cost effective ozone season NOX controls for the

### 2 NOX SIP Call was calculated based on 1990 dollars. If this threshold were

updated based on a more recent year, such as the 2006 year used for recent

EPA RIA documents, the $2,000/ton threshold would become approximately

$3,200 per ton. As a result, EPA believes that controlling to at leas t this level

should be considered, unless air quality considerations suggest an “off

- ramp” at

lower cost levels.

In summary the highest cost threshold for either pollutant considered by EPA in its

program to insure compliance by 2014 with health and welfar e National Ambient Air

Quality Standards was $3,200. In this analysis for reasonable progress for a visibility

aesthetics standard with an ultimate compliance date of 2065 the cost threshold used

was $5,500 per ton.

Baseline Emissions

The three NRG BART

- e ligible units have low annual emissions. Table 1 lists the

maximum 12 month emissions over the period 1/1/200 5 to 12/31/2009 for a three

- year

and five

- year lookback

. Because there has been a significant change in the price of oil

versus natural gas

, oper ations at Oswego have dropped substantially in the past four

years. NRG proposes a three

- year baseline for SO2 and NOx and a more conservative

baseline of five years for PM. Table 2 lists historical annual emissions for the last ten

years. It is not expe cted that the operations at these three units will vary much from the

levels of the last several years in the future. However, as noted in Appendix Y to Part

51

— Guidelines for BART Determinations u nder 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 effe ctiveness threshold for each parameter at each BART

- eligible unit.

Those values will be used to set the future enforceable limits.

Table 1: Maximum Emissions over 3

- year period 1/1/200 7 to 12/31/2009 a nd over

5

- year period 1/1/2005 to 12/31/2009

Arthur Kill Oswego Oswego

Station Unit 30 Unit 5 Unit 6

3

- Yr Maximum 12

- month SO2 Mass 3 1,248 382

3

- Yr Maximum 12

- month NOX Mass 478 243 107

3

- Yr Maximum 12

- month Heat Input 10,470,402 6,878,855 4,791,637

3

- Yr Maximum 12

- month PM Mass 329 33 17

5

- Yr M aximum 12

- month SO2 Mass 3 3,891 1,724

5

- Yr Maximum 12

- month NOX Mass 478 748 476

5

- Yr Maximum 12

- month Heat Input 10,470,402 2,201,269 1,155,665

5

- Yr Maximum 12

- month PM Mass 329 105 71

### 3 Table 2: EPA Clean Air Markets Division Annual Emissions Summa ry Data

( http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=iss.isshome )

Arthur Kill Unit 30

Operating Gross Load SO2 NOx Rate NOx CO2 Heat Input

Year Ti me (MWh) Tons (lb/mmBtu) Tons Tons (mmBtu)

2000 4,571 3.9 0.11 753.0 774,519.4 13,065,427

2001 4,968 1,154,275 3.6 0.11 638.7 719,410.4 12,105,463

2002 3,272 613,649 2.0 0.09 318.5 398,640.7 6,707,896

2003 1,205 175,512 0.6 0.09 96.9 120,775.8 2,032,291

2004 3,060 484,117 1.5 0.07 194.6 298,832.2 5,030,376

2005 3,795 653,562 2.2 0.09 315.3 429,509.8 7,227,282

2006 2,299 382,909 1.3 0.08 193.3 250,340.4 4,212,513

2007 5,333 956,308 3.1 0.0 9 474.8 618,256.1 10,403,297

2008 3,145 507,332 1.6 0.08 235.8 319,756.0 5,380,502

2009 3,062 462,456 1.2 0.09 195.9 236,052.7 3,972,031

Oswego Unit 5

Operating Gross Load SO2 NOx Rate NOx CO2 Heat Input

Year Time (MWh) To ns (lb/mmBtu) Tons Tons (mmBtu)

2000 1,176 252,488 1,528.4 0.19 325.9 257,789.4 3,184,938

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 1,0 87.5 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 1,12 5.5 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

Oswego Unit 6

Operating Gross Load SO2 NOx Rate NOx CO2 Heat Input

Year Time (MWh) Tons (lb/mmBtu) Tons Tons (mmBtu)

2000 571 76,793 189.8 0.17 81.0 70,355.0 962,645

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 19 1,045.3 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

### 4 Summary of Results

Arthur Kill 30

SO2

Arthur Kill 30 burns natural gas (0.0006 lb SO2 per mmBtu) which is better than the

presu mptive limit of 0.15 lb SO2 per mmBtu for an EGU > 200 MW at a plant greater

than 750 MW. The fuel currently being burned should be accepted as BART. The unit

will revise its permit limit equal to the New York City sulfur in fuel limit of 0.3 % or 0.3 lb

per mmBtu if necessary.

PM

There are no cost

- effective controls for BART PM so no permit revisions are needed.

For the natural

- gas fired Arthur Kill Unit 30 simple additives won’t work because there is

no equipment installed to collect the additive. E ven if the control efficiency was 100%

the cost effectiveness of an ESP would be no less than $12,300 per ton as shown in

this report. Finally, note that the maximum 12

- month PM mass over the last five years

is 329 tons so even a 5% reduction in emissions that costs $90,475 would exceed the

$5,500 threshold.

NOx

The a nnual average measured rate 0.088 is better than the oil/gas boiler type RACT

presumptive limit of revised Part 227

- 2, which is 0.15 lb/mmBtu for very large gas/oil

units. To fulfill BART , the unit will revise its permit limit equal to this revised RACT limit.

Oswego 6

SO2

Permit limit is 0.75% sulfur oil which is better than the presumptive limit. The fuel

currently being burned should be accepted as BART.

PM

There are no cost

- effe ctive controls for BART PM under the existing operational mode

of the unit. The unit already has an ESP installed so the most cost

- effective option is for

ESP conditioning. Assuming a control efficiency of 25% for this option, a total annual

cost of $2,5 92,000 (see Table 4), and the most recent measured total PM rate of 0.0296

lb/mmBtu, the annual heat input necessary to make this option cost

- effective, i.e.

increase the annual total emissions, is greater than the capacity of the unit running at

the maxim um hourly heat input 8,760 hours per year. No BART limitations are

necessary for PM.

NOx

There are no cost

- effective controls for BART NOx under the existing operational mode

of the unit. Sargent and Lundy prepared a presumptive NOx RACT/BART analysis of

options for potential controls that concluded that the most cost

- effective control option

was to optimize combustion with burner changes and modify the over

- fired air

configuration to provide more residence time and mixing . Using the control efficienci es

and costs from that report (Table 5), the total annual NOx emissions that would make

### 5 this control option cost effective can be calculated. To fulfill the BART requirement, the

unit will add an annual NOx mass limit of 796 tons.

Oswego 5

SO2

Oswego Unit 5 will revise its permit limit to less than 1.0% sulfur oil. In addition, NRG

recognizes that DEC plans to revise the sulfur in fuel regulations to limit oil to 0.5%.

Because there are fuel handling advantages to a single oil on

- site NRG will immedi ately

commit to purchasing no oil in the future with a sulfur content greater than 0.5% for both

Units 5 and 6.

PM

There are no cost

- effective controls for BART PM under the existing operational mode

of the unit. The unit already has an ESP installed so the most cost

- effective option is for

ESP conditioning. Assuming a control efficiency of 25% for this option, a total annual

cost of $2,896,000 (see Table 4), and the most recent measured total PM rate of 0.0304

lb/mmBtu, the annual heat input necessary to make this option cost

- effective, i.e.

increase the annual total emissions, is greater than the capacity of the unit running at

the maximum hourly heat input 8,760 hours per year. No BART limitations are

necessary for PM.

NOx

There are no cost

- effecti ve controls for BART NOx under the existing operational mode

of the unit. Sargent and Lundy prepared a presumptive NOx RACT/BART analysis of

options for potential controls that concluded that the most cost

- effective control option

was to optimize combusti on with burner changes and modify the over

- fired air

configuration to provide more residence time and mixing. Using the control efficiencies

and costs from that report (Table 5), the total annual NOx emissions that would make

this control option cost effe ctive can be calculated. To fulfill the BART requirement, the

unit will add an annual NOx mass limit of 405 tons.

Emissions Threshold for BART Cost Effective Controls

SO2

Arthur Kill 30 and Oswego Unit 6 SO2 existing emissions are better than the

pres umptive limit of 0.15 lb SO2 per mmBtu for an EGU > 200 MW at a plant greater

than 750 MW. The fuel currently being burned should be accepted as BART.

Oswego Unit 5 Fuel Sulfur Analysis

Oswego Unit 5 currently burns oil greater than the BART presumptive limit so NRG

evaluated the cost differential between 1.5% and 1.0% sulfur fuel oil using historical and

projected cost estimates. This information was coupled with historical fuel use

information to determine a cost to reduce SO2 mass. In both cases the fuel cost

differential is currently so low that the cost per ton is well below the threshold of $5,5000

per ton so NRG will accept a change in the fuel oil limits for Unit 5 to less than 1.0%

sulfur oil

.

### 6 NRG recognizes that DEC plans to revise the sulfur in fuel regulations to limit oil to

0.5%. Because there are fuel handling advantages to a single oil on

- site NRG will

immediately commit to purchasing no oil in the future with a sulfur content greater than

0.5% for both Units 5 and 6. No oil has been de livered to the station since 11/1/2006.

However, because the current fuel use is so low, NRG will request to use any oil

currently on

- site in the future, even if that comes after the effective date of the sulfur in

fuel revision.

PM

The document “Assessm ent of Control Options for BART

- Eligible Sources : Steam

Electric Boilers, Industrial Boilers, Cement Plants and Paper and Pulp Facilities

prepared by Northeast States for Coordinated Air Use Management In Partnership with

The Mid

- Atlantic/Northeast Visibil ity Union dated March 2005 describes PM controls. It

notes that there are f our types of control devices are used to collect PM emissions from

coal

- fired electric utility boilers: electrostatic precipitators, fabric filters, mechanical

collectors, and part icle scrubbers. There is no discussion of gas and oil fired boilers.

Note that t he major difference is that oil

- f ired particulate emissions are fewer in number

and smaller in size than coal

- fired PM emissions in general and that gas fired particulate

emi ssions are much fewer and smaller than oil

- fired PM emissions. As a result

mechanical collectors are less effective for oil

- and gas

- fired boiler PM emissions.

The BART analysis requirements note that we have to identify potential retrofit emission

contr ol technologies and ”where already in place, improvement in the performance of

add

- on controls, such as scrubbers, fabric filters, thermal oxidizers and other devices

that control and reduce emissions after they are produced”. Arthur Kill 30 has no

pollut ion control equipment installed but both Oswego units have ESPs. The following

analysis shows it is not possible to install new control systems that would not exceed

the $5,500 threshold because baseline emissions are so small. The analysis also

document s that the existing ESPs at Oswego have already been tuned so further

incremental reductions are not cost

- effective.

It is not expected that there are any cost

- effective controls for PM. The three NRG units

that are covered by the BART regulation all hav e relatively low recent SO2, NOx and

PM emissions. Table 3 lists the maximum 12

- month PM emissions and an estimate of

the amount to spend that would exceed the $/ton threshold . This estimate is calculated

by simply multiplying the cost effectiveness thre shold times the number of tons

expected to be reduced (the maximum emissions times an assumed control efficiency.

For example, Arthur Kill 30 emitted 322 tons of PM. If there was a control measure that

could get a minimum 5% reduction and cost less than $88,503 then it would meet the

$5,500 threshold. If it costs more or does not get at least that reduction for that cost,

then it would exceed the $5,500 threshold.

### 7 Table 3 : Particulate Matter Cost Threshold Analysis

Particulate Matter Arthur Kill Oswego Oswego % Control

Unit 30 Unit 5 Unit 6 Reduction

Five Year Look Back Maximum Emissions 329 105 71

Amount to spend to exceed $/ton threshold $ 18,095 $ 5,775 $ 3,905 1%

Amount to spend to exceed $/ton threshold $ 90,475 $ 28,875 $ 19,525 5%

Amount to spend to exceed $/ton threshold $ 180,950 $ 57,750 $ 39,050 10%

Amount to spend to exceed $/ton threshold $ 271,425 $ 86,625 $ 58,575 15%

Amount to spend to exceed $/ton threshold $ 452,375 $144,375 $ 97, 625 25%

Amount to spend to exceed $/ton threshold $ 904,750 $288,750 $195,250 50%



### Arthur Kill 30 PM Analysis

Arthur Kill 30 burns natural gas and our evaluation of emissions indicates that there are

no controls available that would not exceed the $5,500 threshold. The document

“Assessment of Control Options for BART

- Eligible Sources : Steam Electric Boilers,

Industrial Boilers, Cement Plants and Paper and Pulp Facilities prepared by Northeast

States for Coordinated Air Use Management In Partnershi p with The Mid

Atlantic/Northeast Visibility Union dated March 2005 lists costs for PM control

equipment that were used for this assessment. The lowest values listed for each option

listed below were used:

The following values represent typical costs fo r application of ESPs to units

handling a range of flue gas rates (these numbers reflect unit sizes ranging from

utility

- size units up to about 2,000,000 ACFM to smaller process down to about

10,000 ACFM):

Capital: $15

- $40/ACFM

Fixed O&M: Dry ESP’s

- $0. 25

- $0.65/yr

- ACFM

Wet ESP’s

- $0.15

- $0.50/yr

- ACFM

Variable O&M: Dry ESP’s

- $0.45

- $0.60/yr

- ACFM

Wet ESP’s

- $0.25

- $0.50/yr

- ACFM

Baghouses have been used extensively for many years in different industries.

The EGU sector, while predominantly dominated by ESP’s, has started to utilize

FF’s in the last 20 years.

Capital: Reverse Air Fabric Filter

- $17

- $40/ACFM

Pulse Jet Fabric Filter

- $12

- $40/ACFM

Fixed O&M: Reverse Air Fabric Filter

- $0.35

- $0.75/yr

- ACFM

Pulse Jet Fabric Filter

- $0.50

- $0.90/y r

- ACFM

Variable O&M: Reverse Air Fabric Filter

- $0.70

- $0.80/yr

- ACFM

Pulse Jet Fabric Filter

- $.90

- $1.1/yr

- ACFM

It is assumed that scrubbing system costs would be greater than the costs for ESP or

fabric filters so no analysis for that application is included.

Table 4 summarizes the economic analysis in the same format as the DEC Air Guide 20

report. For the baseline PM emissions rate of 32 9 tons per year, the total cost per ton

reduced for an ESP with 99.9% control efficiency is $12, 110 and for a ba ghouse is

$ 12,994 . If the PM actual emissions were 72 4 tons per year, then an ESP operating at

99.9% control efficiency would be cost effective. Note that all these are preliminary

### 8 numbers using the most conservative assumptions so this tonnage threshold is very

likely conservative.

Oswego Units 5 and 6 PM Analysis

Oswego Units 5 and 6 already have an ESP installed. The most recent PM stack tests

on Unit 5 measured a total PM rate of 0.0304 lb/mmBtu and a filterable PM rate of

0.0217 lb/mmBtu. The most recent PM stack tests on Unit 6 measured a total PM rate

of 0.0296 lb/mmBtu and a filterable PM rate of 0.0218 lb/mmBtu.

According to the Air Pollution Control Technology Fact Sheet for dry electrostatic

precipitators

– wire plate type (EPA

- 452/F

- 03

- 028) precipitator size is related to many

design parameters:

One of the main parameters is the specific collection area (SCA), which is

defined as the ratio of the surface area of the collection electrodes to the gas

flow. Higher collection areas lead to bett er removal efficiencies. Collection areas

normally are in the range of 200 to 800 ft 2 

### /1000 scfm, with typical values of 400

ft 2 

### /1000 scfm.

The Oswego 5 and 6 specific collection area is 389 ft 2 

### per 1000 scfm so these are

typical ESPs although note that b ecause the units are oil

- fired the initial particulate

emissions are lowe r than from a coal

- fired boiler so they can be considered over

- sized

for oil

- firing units.

Table 5 summarizes the economic analysis in the same format as the DEC Air Guide 20

report. For the baseline PM emissions rate s , the total cost per ton reduced for a

baghouse is $ 40,588 for Unit 5 and $ 57,275 for Unit 6. If the PM actual emissions were

77 2 tons per year on Unit 5, then a baghouse operating at 99.9% control efficiency

would be cost effective. For Unit 6 if the PM actual emissions were 738 tons per year,

then a baghouse operating at 99.9% control efficiency would be cost effective Note that

all these are preliminary numbers using the most conservative assumptions so this

tonnage threshold is very likely conservative.

The NESCAUM report also includes costs for ESP conditioning. For the baseline

emission rates and assuming a wildly optimistic control efficiency of 75% (beyond what

is gained from just the ESP) the cost of controls per ton reduced is over an order of

magnitude greater than the $5,500 per ton threshold. Using a more realistic control

efficiency of 25%, Unit 5 emissions would have to be greater than 2107 tons to be cost

effective and Unit 6 emissions would have to be greater than 1885 tons to be cost

effective.

### 9 Table 4 : DEC Air Guide 20 Economic Analysis

– PM Air Emissions Control

Equipment at NRG Arthur Kill Unit 30

Facility Name Arthur Kill

4401 Victory Blvd

Staten Island, NY 10314

Facility ID Arthur Kill 30 Arthur Kill 30

Emission Point Control Type ESP Fabric Filter

Stack Gas Volume (acfm) 1,699,028 1,699,028

Costs ($/ACFM)

Capital $ 15.00 $ 12.00

Fixed O&M $ 0.15 $ 0.25

Variable O&M $ 0.25 $ 0.70

1 Cost of Emissions Control Equipment including installation $ 25,485,425 $20,388,340

2 Calculate Capital Recovery Factor 0.130 0.130

I= Annual interest rate 5% 5%

n= Equipment or replacement parts life in yea rs (n=10) 10 10

3 Calculate Annual Equipment Cost (Multiply Item 1 by Item 2 $ 3,300,479 $ 2,640,383

4 Annual Operating Costs $ 679,611 $ 1,614,077

4A Fixed O&M $ 254,854 $ 424,757

4B Variable O&M $ 424,757 $ 1,189,320

5 Total Annual Costs (Add items 3 and 4[A to e]) $ 3,980,090 $ 4,254,460

6 Calculate Annual PM Tonnage Reduction

6A PM actual annual emissions 329.0 329.0

6B Percent capture and control achieved 99.9% 99.9%

6C Tons reduc ed (multiply item 6A by 6B) 328.7 328.7

Total Cost of Controls per Ton Reduced (Divide Item 5 by

Item 6C) $ 12,372.90 $ 12,944.43

Control costs from "Assessment of Control Technology Options for BART

- Eligible Sources

Steam Electric Bo ilers, Industrial Boilers, Cement Plants and Paper and Pulp Facilities"

Prepared by Northeast States for Coordinated Air Use Management in partnership with

The Mid

- Atlantic/Northeast Visibility Union, March 2005

7 Back

- Calculate Annual PM Ton nage Limit

7A Percent capture and control achieved 99.9% 99.9%

7B Threshold Tons reduced (divide item 5 by 7C) 723.7 773.5

7C Effective Control Cost Threshold ($/ton) $5,500 $5,500

7D PM actual annual emissions (divide 7B by 7A) 724.4 774.3

### 10 Ta ble 5 : DEC Air Guide 20 Economic Analysis

– PM Air Emissions Control Equipment at NRG Oswego Units 5 and 6

Facility Name NRG Oswego Harbor Power

261 Washington Blvd , Oswego, NY 13126

Facility ID Oswego 5 Oswego 6 Oswego 5 Oswego 6

Emission Point Control Type Fabric Filter ESP Conditioning

Stack Gas Volume (acfm) 1,810,533 1,620,077 1,810,533 1,620,077

Costs ($/ACFM)

Capital $ 15.00 $ 12.00

Fixed O&M $ 0.15 $ 0.25

Variable O&M $ 0.25 $ 0.70 $ 1.60 $ 1.60

1 Cost of Emissions Control Equipment including installation $ 27,158,000 $ 19,440,920 $

- $

-

2 Calculate Capital Recovery Factor 0.130 0.130 0.130 0.130

I= Annual interest rate 5% 5% 5% 5%

n= Equipment or replacement parts life in years (n=10) 10 10 10 10

3 Calculate Annual Equipment Cost (Multiply Item 1 by Item 2 $ 3,517,085 $ 2,517,688 $

- $

-

4 Annual Operating Costs $ 724,213 $ 1,539,073 $ 2,896,853 $ 2,592,123

4A Fixed O&M $ 271,580 $ 405,019 $

- $

-

4B Variable O&M $ 452,633 $ 1,134,054 $ 2,896,853 $ 2,592,123

5 Total Annual Costs (Add items 3 and 4[A to e]) $ 4,241,299 $ 4,056,761 $ 2,896,853 $ 2,592,123

6 Calculate Annual PM Tonnage Reduction

6A PM actual annual emissions 104.6 70.9 104.6 70.9

6B Percent capture and control achieved 99.9% 99.9% 75.0% 75.0%

6C T ons reduced (multiply item 6A by 6B) 104.5 70.8 78.5 53.2

Total Cost of Controls per Ton Reduced (Divide Item 5 by Item 6C) $ 40,588.38 $ 57,275.34 $ 36,926.11 $ 48,747.02

Control costs from "Assessment of Control Technology Options for BART

- Eligible Sources

Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper and Pulp Facilities"

Prepared by Northeast States for Coordinated Air Use Management in partnership with

The Mid

- Atlantic/Northeast Visibility Union, Ma rch 2005

7 Back

- Calculate Annual PM Tonnage Limit

7A Percent capture and control achieved 99.9% 99.9% 25.0% 25.0%

7B Threshold Tons reduced (divide item 5 by 7C) 771.1 737.6 526.7 471.3

7C Effective Control Cost Threshold ($/ton) $5,500 $5,5 00 $5,500 $5,500

7D PM actual annual emissions (divide 7B by 7A) 771.9 738.3 2106.8 1885.2

### 11 The more cost

- effective option is for ESP conditioning and that cannot meet the $5,500

threshold. The total annual emissions necessary to make this cost

- effect ive can be

calculated. Assume a control efficiency of 25% for this option, the total annual cost of

control shown in Table 5 and the most recent measured total PM, the annual heat input

necessary to make this option cost

- effective can be determined. For both Units 5 and 6

the heat input necessary to produce those emissions is greater than the each unit

running at the maximum hourly heat input 8,760 hours per year.

As part of the BART analysis, NRG has to identify potential retrofit emission control

tec hnologies and ”where already in place, improvement in the performance of add

- on

controls, such as scrubbers, fabric filters, thermal oxidizers and other devices that

control and reduce emissions after they are produced”. In the last ten years of its

owner ship of Oswego Harbor Power, NRG has had a systematic process in place to

upgrade the performance of these precipitators. For example, opacity monitors have

been installed in the ducts between the furnace and the precipitators to assist the

operators to m onitor burner conditions before they impact the opacity

.

Other ESP improvements include the following:

 Unit #6 Voltage controls were upgraded to the new Neundorfer Micro Voltage

Controls. Unit 5 already had these digital control system installed.

 A new pl ant operating system c omputer was installed to monitor both Units 5 and

6 v oltage c ontrol operating parameters when online. This gives the ability to

troubleshoot more effectively as well as run reports on previous runs.

 NRG has straightened warped plates in Unit 5 and 6 by pulling ladder bars

between the plates that had mechanical alignment issues.

 NRG also contracted a Field Engineer from TRK to help us tune the Voltage

Controls for optimized performance.

We conclude that significant improvements in the ESP control systems have already

been implemented.

Moreover, even if there were additional improvements possible the costs to implement

would likely preclude a cost effective project. NRG’s Dunkirk and Huntley generating

stations had even more extensive ESP upgrade programs over the period 2000

– 2007.

There were a total of 16 ESP improvement projects. The cheapest ($30,000) was to

install an opacity monitor in the duct work and that has already been done at Oswego.

The next cheapest project was entit led “ Precipitator Key Lock System Replacement ”

and that cost $60,000. Using DEC’s Air Guide 20 methodology solely for the costs of

installation and assuming a 2.5% improvement in PM emissions yields a cost per ton

removed of $6,094 per ton for Oswego Unit 5.

NOX

The Arthur Kill 30 a nnual average measured rate ( 0.088 lb/mmBtu) is better than the

oil/gas boiler type RACT presumptive limit of revised Part 227

- 2, which is 0.15 lb/mmBtu

for very large gas/oil units. To fulfill BART, the unit will revise its p ermit limit equal

to this revised RACT limit.

### 12 Oswego 5 and 6 NOx Control Analysis

NRG contracted Sargent & Lundy LLC of Chicago, Illinois to evaluate technologies to be

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

th e attached document. The Sargent & Lundy analysis included a site visit; a re view of

e xisting operational d ata, b oiler d rawings, and emissions; an evaluation of the f easibility

and e ffectiveness of p otentially available combustion controls/m odifications i ncluding

burner modifications, over

- fired air , natural gas re

- burn, burners out of service

, and flue

gas re

- circulation; an evaluation of the t echnical f easibility and e ffectiveness of

SNCR/SCR control s ystems ; and developed b udgetary c ost e stimates for th e

technically feasible control technologies ( b udgetary $/kW costs based on industry

averages.)

The executive summary of the report states:

This engineering report was prepared to support the Oswego Unit 5 & 6 RACT

compliance evaluation and BART determinat ion, focusing on the control of NOx

emissions from both units. This evaluation follows the BART determination

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 baseline NOx emissions from each units, identifies and

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

provides budgetary cost estimates and calculates the cost

- effectiveness of each

technicall y 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 annu al 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 t echnically 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

ap proximately $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 emissions are low because

of the low capacity factors achieved by both units during the baseline period.

### 13 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,

i ncluding 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 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 poten tial 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 lb/mmBtu for Unit 5 and 0.19 lb/mmBtu for Unit 6) and an annual capacity factor 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 boilers' combustion control systems. For the

control options that only included changes to the LN

- R EACH 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

- sp ecific, 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.

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

which there are no NOx control technol ogies available that has cost

- effectiveness less

than the DEC’s threshold of $5,500 per ton has to be calculated (Table 6)

. A s 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 Uni t 5, Option 2 (LN

- REACH (pressu r i zed atomizers) and modified OFA)

crosses the $5,500/ton threshold at an annual capacity factor of app roximately 5.4%

(3,677,661 mmBtu/yr or baseline NOx rate of 405 t ons p er y ear ) as shown in Figure 1

.

### 14 0.0 50.0 100.0 150.0 200.0 250.0 300.0 350.0 400.0 450.0 500.0

3.2% 4.0% 5.0% 5.2% 5.3% 5.5% 6.0% $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 $10,000 Baseline Emissions Projected Emissions Cost Effectiveness

Figure 1 : Os wego Unit 5 Cos t Effectivenes s with Capacity Factor for Sargen t and Lundy Option 2

0.0 100.0 200.0 300.0 400.0 500.0 600.0 700.0 800.0 900.0

3.2% 6.0% 9.0% 11.0% 12.0% $0 $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $16,000 $18,000 $20,000 Baseline Emissions Projected Emissions Cost Effectiveness

Figure 2 : Os wego Unit 6 Cos t Effectivenes s with Capacity Factor for Sargen t and Lundy Option 2

### 15 Table 6 : 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) ($/yr) ($/ton)

3.2% 2,201,269 242.1 198.1 44.0 $384,900 $8,748

4.0% 2,726,822 300.0 245.4 54.6 $391,500 $7,170

5.0% 3,424,888 376.7 308.2 68.5 $399,900 $5,838

5.2% 3,561,884 391.8 320.6 71.2 $401,500 $5,639

5.3% 3,633,122 399.6 327.0 72.6 $402,400 $5,543

5.5% 3,792,967 417.2 341.4 75.8 $404,000 $5,330

6.0% 4,107,907 451.9 369.7 82.2 $408,200 $4,966

Uni t 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) ($/yr) ($/ton)

3.2% 2,212,028 210.1 188.0 22.1 $384,900 $17,416

6.0% 4,11 5,405 391.0 349.8 41.2 $408,200 $9,908

9.0% 6,160,815 585.3 523.7 61.6 $433,200 $7,032

11.0% 7,523,040 714.7 639.5 75.2 $449,900 $5,983

12.0% 8,259,414 784.6 702.1 82.5 $458,200 $5,554

13.0% 8,956,730 850.9 761.3 89.6 $466,500 $5,206



### On Unit 6, Optio n 2 crosses the $5,500/ton threshold at a capacity factor of

approximately 12.2% (8,397,519 mmBtu/yr or baseline NOx rate of 796 t ons p er y ear)

as shown in Figure 2.

Presumably, these numbers could be used to establish a permit condition restricting

opera tions on the two units. However, the difference in the tonnage limits between two

very similar units is striking. Sargent and Lundy presumed that the lower baseline NOx

emission rate on Unit 6 is because Unit 6 is typically fired at lower boiler O2 levels

. NRG believes that it is more likely that the operational pattern of the two units during the

baseline period was the reason for the difference in emissions at the two units and thus

the baseline emission rates. Table 7 compares the 2007

- 2009 NOx rate w ith load

curves based on a regression of observed values , observed hours within each load bin,

and a pr ojection of the mass within each load bin. The projected NOx mass was

calculated by multiplying the NOx Rate regression value for each load by a similar

regression value for heat input times the number of hours in the corresponding load bin.

While there is a minor difference in the NOx rates between the units at the same load

levels there were many more hours at the higher loads on Unit 5 than Unit 6 wher e the

NOx rates are much higher. As a result the baseline NOx mass is higher for Unit 5.

The table also lists NOx mass emissions when the Unit 5 hours were used with the Unit

6 NOx rate with load curve that shows that the controlling factor is more likel y the higher

emission rates at higher loads.

### 16 Table 7 : Oswego Station 2007

– 2009 Linear Regression NOx Rate with Load

Curve, Number of Hours in Each Load Bin, and Predicted NOx Mass for Each

Load Bin

Observed NOx Rate Observed Hours Predicted NOx Mas s

Load Unit 5 Unit 6 Unit 5 Unit 6 Unit 5 Unit 6 5 Hrs & 6 NOXR

100 0.166 0.132 20 21 2.7 2.3 2.2

150 0.172 0.139 214 127 39.2 18.5 31.2

200 0.178 0.147 68 53 15.8 10.0 12.8

250 0.185 0.154 37 28 10.6 6.5 8.6

300 0.191 0.162 59 51 20.1 14.4 16.6

350 0.197 0.170 27 29 10.8 9.7 9.1

400 0.203 0.177 13 22 6.0 8.6 5.1

450 0.209 0.185 18 15 9.4 6.8 8.1

500 0.216 0.193 12 17 7.1 8.7 6.2

550 0.222 0.200 15 22 10.0 12.7 8.7

600 0.228 0.208 16 21 11.8 13.7 10.4

650 0.234 0.215 24 14 19.5 10.1 17.3

700 0 .241 0.223 33 11 29.5 8.8 26.4

750 0.247 0.231 16 13 15.6 11.5 14.1

800 0.253 0.238 38 21 40.3 20.3 36.6

850 0.259 0.246 48 41 55.1 43.2 50.6



### In the past there has been a cost penalty for operating Unit 6 relative to Unit 5 because

of the cost differe nce between the sulfur content of the fuel. As a result, Unit 5 was

operated at the higher loads preferentially because it was cheaper to operate. The

baseline data reflect this preference. If the operating limits are based on these unit

specific data, then Unit 5 will be restricted more than Unit 6 and Unit 6 will run

preferentially because of this baseline artifact. It makes more sense to establish a

single limit that applies to both units.

NRG will propose 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 below which there are no NOx control technologies available that has cost

effectiveness less than the DEC’s threshold of $5,500 per ton was 4 05 tons for Unit 5

and 796 tons for Unit 6. In order to address the baseline artifact issue, the permit could

include a station trigger of 1,201 tons (the sum of both unit caps) or simply take the

average of the sum of the totals and establish unit trigge r s of 600 tons per year.