Entergy

Arkansas Environmental Support

425 West Capitol Avenue

A-TCBY-22D

Little Rock, AR 72203

Tel 501-377-4033

Fax 281-297-6128

G. Tracy Johnson, Manager

Arkansas Environmental Support

AR-i 2-078

October 14, 2013

Mr. Mike Bates

Chief, Air Division

Arkansas Department of Environmental Quality

5301 Northshore Drive

North Little Rock, AR 72118

RE: Entergy Arkansas, Inc. — White Bluff Plant

Revised BART Five-Factor Analysis

Permit No, 0263-AOP-R7, AFIN 35-00110

Dear Mr. Bates:

Please find attached a revised and updated Best Available Retrofit Technology (BART) FiveFactor Analysis (FFA) for the Entergy Arkansas, Inc — White Bluff Plant. This updated FFA was

completed in order to incorporate revisions made to the analysis in response to questions

received from EPA Region 6 staff regarding the revised FFA which was submitted on June 10,

2013.

In addition to the revised FFA document, we have enclosed a question and answer document in

which we directly respond to each specific issue raised in EPA’s comments.

We appreciate ADEQ’s consideration of this analysis and additional supporting information.

Should you or your staff have any questions regarding this submittal, please contact me at

(501) 377-4033 or David Triplett at (501) 377-4030.

Sincerely,

G. Tracy Jol

Manager, Arkansas

GTJ/dct

Environmental Support

CC: Mary Pettyjohn, ADEQ (via email)

1
Entergy Response to 8/21/2013 EPA Region 6 comments on the White Bluff BART FFA

Entergy has reviewed the comments provided by EPA Region 6 on August 21, 2013, and appreciates the

opportunity to provide the below response. To simplify the format of this response, we have included

each of EPA’s comments, followed by our response. Submitted concurrently herewith is a revised FiveFactor Analysis (FFA) incorporating several revisions as discussed below.

NOx BART

x EPA Comment 1 - The 2012 S&L NOx Study identifies neural net system upgrades as a

potential NOx control. However, this control option is not evaluated by Entergy in the BART

analysis for Units 1 and 2. While it appears that the added visibility benefit of LNB/SOFA +

SNCR compared to LNB/SOFA is too small to justify the added cost of installing SNCR, we

believe the added cost of LNB/SOFA + Neural Net System Upgrades compared to LNB/SOFA

would likely be small and may provide some visibility benefit. ADEQ should ensure that if a

NOx emission limit more stringent than 0.15 lb/MMBtu could be expected from LNB/SOFA +

Neural Net System Upgrades, this should be evaluated as a separate control option in the BART

analysis.

Entergy Response – Entergy does not believe that operation of neural network system upgrades

in conjunction with LNB/SOFA would result in a NOx emission limit more stringent than the

0.15 lb/MMBtu proposed in the FFA. The information1 presented in the S&L NOx study

regarding neural network system upgrades was an estimate of the level of NOx reductions which

could potentially be achieved through implementation of neural network system upgrades for the

White Bluff units as currently configured (without LNB/SOFA). As no vendor guarantees were

available for the NOx performance of such neural network system upgrades, and the level of

NOx emission reduction estimated by S&L from the operation of neural network system

upgrades alone (10%) was significantly less than the potential NOx emission reductions

achievable by other evaluated control technologies, no consideration was given to this option in

the FFA.

Since receiving this question from EPA, Entergy has conducted additional discussions with S&L

regarding the potential for neural network system upgrades to be operated in conjunction with

LNB/SOFA to achieve additional levels of NOx control beyond that expected from LNB/SOFA

alone. S&L provided the following statement on this subject.

The Neural Network (NN) is a computer program that evaluates controllable parameters

affecting the NOx emission rate from the boiler and learns over a long period of

operation (years) how to minimize the NOx emission rate. The suppliers of NN do not

1

 Percent NOx emission reduction and expected NOx emission rates
offer a guarantee on NOx emission rate or percent reduction. The primary benefit is to

maintain over time the guaranteed NOx emission rate performance resulting from

LNB/SOFA. There are NN installations that have achieved small improvements in NOx

emission rate over a long period of time but as previously stated, the NN suppliers aren't

offering guarantees and the NN may take many years to realize the performance

improvement. While this combination of technologies may be desirable in the long run,

we don't recommend it as a separate NOx control option to be evaluated in the BART

analysis.

Based on the lack of a NOx emission reduction guarantee, Entergy does not believe that the

combination of NN system upgrades with LNB/SOFA should be evaluated as a separate, distinct

control option within the FFA.

Cost Analysis for SO2 and NOx Controls

x EPA Comment 2 - We are not providing an exhaustive line-by-line review of costs for SO2 and

NOx controls because we do not anticipate that further revisions to the cost numbers would

change the ultimate BART determinations. However, we wish to make clear that EPA disagrees

that the Control Cost Manual (CCM) allows for AFUDC to be included in the BART cost

evaluation. AFUDC is the cost of capital that is incurred to finance the project during the

construction period. While AFUDC is a valid cost under the all-in cost estimating methodology,

it is not a valid cost under the CCM methodology. The Regional Haze Rule states the CCM

should be followed where possible, and the CCM uses overnight costing methodology. The

overnight cost method is the cost of a construction project if no interest is incurred during

construction, as if the project is completed overnight. Thus, AFUDC is never valid under the

CCM overnight cost approach. ADEQ should ensure that the cost estimates for all SO2 and

NOx controls are revised to exclude AFUDC in order to reflect an accurate estimate of costeffectiveness of controls.

Entergy Response – Entergy continues to believe that the overnight costing methodology

advocated by EPA represents an overly simplistic view of the true costs associated with a

significant pollution control project such as those evaluated by Entergy in this FFA. AFUDC

represents the interest expense on the investment in the technology that is incurred during

construction, before the equipment is placed in service. For major control technology

installations, such as scrubbers or SCR, the interest expense incurred during the 30 - 46 months

of construction can reach $30 million to $60 million for a large unit. AFUDC simply includes

the interest as part of the capital cost, which is standard accounting and rate-making treatment of

such costs.

Entergy does not agree that the CCM requires the company to exclude AFUDC from control

technology costs. Nonetheless, although Entergy is not waiving its ability to include AFUDC in
future control cost analyses, to expedite ADEQ’s consideration of the FFA for White Bluff, we

have revised the FFA document to remove AFUDC from the costs of each evaluated pollution

control technology as requested by EPA staff. While this change lowers the overall capital costs

presented within the latest FFA, the BART determinations for each affected pollutant (SO2 and

NOx) remain unchanged.

Auxiliary Boiler (SN-05)

x EPA Comment 3 - The calculations provided indicate that average sulfur content over the

2009-2011 period and the average heat content over this same period were utilized to estimate

the modeled emission rate. The use of average values based on a three year average of annual

values is inconsistent with estimating the maximum 24-hr emission rate from the baseline

period. Please provide additional information on the variability of sulfur content and heat

content in order to estimate the range of the maximum impact.

Entergy Response – Entergy reviewed the monthly fuel oil sampling data for the facility along

with daily records of aux. boiler hours of operation for 2009-2011. Over the 2009-2011 period,

the heat content of the fuel oil ranged from 134,318 btu/gal to 142,422 btu/gal, and the sulfur

content ranged from 0.004% to 0.056%2. By combining each month’s fuel sampling result for

heat and oil sulfur content with the maximum daily hours of operation for the aux. boiler for the

month, it is possible to produce a refined estimate of the maximum daily (24-hour) average SO2

emission rate from this unit.

Based on this data, the maximum 24-hour average SO2 emission rate occurred on May 10, 2009.

The monthly fuel analysis for May 2009 indicates a heat content of 135,438 btu/gal (135.438

MMBtu/Mgal) and a sulfur content of 0.0441% by weight. Based on the emission factor

presented in AP-42 Table 1.3-1 for distillate fuel-fired boilers of >100 MMBtu/hr (142S

lb/Mgal), the SO2 emission factor for May 2009 is calculated as 0.0462 lb/MMBtu. At the

maximum 24-hour average heat input rate for May 2009 of 121.23 MMBtu/hr3, the maximum

24-hour average SO2 emission rate for the 2009-2011 period is calculated as 5.61 lb/hr.

This refined estimate of the maximum baseline 24-hour SO2 emission rate for the aux. boiler is

less than the rate (5.8 lb/hr) which was utilized to estimate the baseline visibility impairment

2

 Entergy notes that the sulfur content of the No. 2 fuel oil used at White Bluff has trended downward over time, with the

annual average sulfur content for 2011 being 0.013% and the average for 2012 being 0.0042%. Due to the increasing

restrictions on the sulfur content of commercially available No. 2 fuel oil, it is unlikely that the sulfur content in future years

will return to past levels.

3

 This rate was calculated based on the maximum daily hours of operation in May of 2009 (15.9 hours on May 10) and the

maximum heat input capacity of the aux. boiler (183 MMBtu/hr). This calculation assumes that the aux. boiler was operating

at the maximum rated capacity at all times that it was online on this date. This assumption results in an over-estimate of the

actual average heat input for this date.
attributable to this unit. As such, the analysis presented within the FFA is conservative and no

refinement to the modeled SO2 emission rate for the aux. boiler is necessary.

x EPA Comment 4 - The rationale for determining that no additional controls are required for this

unit differs in the revised BART report and the response to Region 6 comments you provided

(comment 16). Please revise the BART report to be consistent with your response to our

comments, as the response provides an appropriate justification for no additional controls at the

auxiliary boiler.

Entergy Response – The BART FFA report has been revised to include the rationale for

determining that no additional controls are required for the auxiliary boiler which was presented

in the June 2013 response to comments document.
REVISED BART FIVE FACTOR ANALYSIS

WHITE BLUFF STEAM ELECTRIC STATION

REDFIELD, ARKANSAS (AFIN 35-00110)

Prepared By:

TRINITY CONSULTANTS, INC.

201 NW 63rd St., Suite 220

Oklahoma City, Oklahoma 73116

(405) 848-3724

TRINITY CONSULTANTS, INC.

977 Ridge Drive, Suite 380

Lenexa, Kansas 66219

(913) 894-4500

In conjunction with:

ENTERGY SERVICES, INC.

425 West Capitol Avenue

Little Rock, Arkansas 77203

 (501) 377-4000

Trinity Project No. 123701.0053

October 2013
Entergy i Trinity Consultants

BART Analysis – White Bluff

TABLE OF CONTENTS

1. EXECUTIVE SUMMARY .................................................................................... 1-1

2. INTRODUCTION AND BACKGROUND ................................................................. 2-1

3. MODELING METHODOLOGIES AND PROCEDURES ........................................... 3-1

3.1 CALMET AND CALPUFF................................................................................ 3-1

3.2 CALPOST ....................................................................................................... 3-1

4. EXISTING EMISSIONS AND VISIBILITY IMPAIRMENT ....................................... 4-1

4.1 NOX, SO2, AND PM10 BASELINE EMISSION RATES ............................................. 4-1

4.2 BASELINE VISIBILITY IMPAIRMENT .................................................................... 4-2

5. SO2 BART EVALUATION ................................................................................. 5-1

5.1 IDENTIFICATION OF AVAILABLE RETROFIT SO2 CONTROL TECHNOLOGIES FOR

SN-01 AND SN-02 ............................................................................................ 5-1

5.2 ELIMINATE TECHNICALLY INFEASIBLE SO2 CONTROL TECHNOLOGIES FOR

SN-01 AND SN-02 ............................................................................................ 5-1

5.2.1 DRY SORBENT INJECTION................................................................................ 5-1

5.2.2 SEMI-DRY SCRUBBER ..................................................................................... 5-2

5.2.3 WET SCRUBBER .............................................................................................. 5-2

5.3 RANK OF TECHNICALLY FEASIBLE SO2 CONTROL OPTIONS BY EFFECTIVENESS

FOR SN-01 AND SN-02 ..................................................................................... 5-3

5.4 EVALUATION OF IMPACTS FOR FEASIBLE SO2 CONTROLS FOR SN-01 AND

SN-02 .............................................................................................................. 5-3

5.4.1 COST OF COMPLIANCE .................................................................................... 5-4

5.4.2 ENERGY IMPACTS AND NON-AIR QUALITY IMPACTS ....................................... 5-7

5.4.3 REMAINING USEFUL LIFE ................................................................................ 5-7

5.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE SO2 CONTROLS FOR SN-01

AND SN-02 ....................................................................................................... 5-7

5.6 PROPOSED BART FOR SO2 FOR SN-01 AND SN-02 .............................................5-13

5.6.1 COMPARATIVE SO2 BART DETERMINATIONS ............................................... 5-13

5.7 SO2 BART FOR SN-05 ......................................................................................5-14

6. NOX BART EVALUATION ............................................................................... 6-1

6.1 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL TECHNOLOGIES

FOR SN-01 AND SN-02 ..................................................................................... 6-1

6.2 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES .............. 6-1

6.2.1 COMBUSTION CONTROLS ................................................................................ 6-2

6.2.1.1 Flue Gas Recirculation (FGR)........................................................... 6-2

6.2.1.2 Overfire Air (OFA) / Separated Overfire Air (SOFA) ....................... 6-2

6.2.1.3 Low NOX Burners (LNB) ................................................................. 6-3

6.2.2 POST COMBUSTION CONTROLS ....................................................................... 6-3
Entergy ii Trinity Consultants

BART Analysis – White Bluff

6.2.2.1 Selective Catalytic Reduction (SCR) ................................................. 6-3

6.2.2.2 Selective Non-Catalytic Reduction (SNCR) ...................................... 6-3

6.3 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY EFFECTIVENESS . 6-5

6.4 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS .................................. 6-5

6.4.1 COST OF COMPLIANCE .................................................................................... 6-5

6.4.2 ENERGY IMPACTS & NON-AIR IMPACTS .......................................................... 6-9

6.4.3 REMAINING USEFUL LIFE ................................................................................ 6-9

6.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS ...................6-10

6.6 PROPOSED BART FOR NOX FOR SN-01 AND SN-02 ...........................................6-16

6.7 PROPOSED BART FOR NOX FOR SN-05 ..............................................................6-16

7. PM10 BART EVALUATION .............................................................................. 7-1

APPENDIX A (SO2 AND NOX CONTROL COST CALCULATIONS)

APPENDIX B (BASELINE VISIBILITY IMPAIRMENT BY POLLUTANT)

APPENDIX C (CALMET MODELING PROTOCOL)

APPENDIX D (CEMS DATA FROM CAMD FOR 2001 TO 2003 AND 2009 TO 2011)

APPENDIX E (S&L NOX CONTROL TECHNOLOGY STUDY)
Entergy iii Trinity Consultants

BART Analysis – White Bluff

LIST OF TABLES

TABLE 1-1. MODELED EXISTING VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-01, SN-02

 AND SN-05.................................................................................................................... 1-2

TABLE 3-1. ANNUAL AVERAGE BACKGROUND CONCENTRATION .................................................. 3-3

TABLE 3-2. FL(RH) LARGE RH ADJUSTMENT FACTORS .................................................................. 3-3

TABLE 3-3. FS(RH) SMALL RH ADJUSTMENT FACTORS .................................................................. 3-3

TABLE 3-4. FSS(RH) SEA SALT RH ADJUSTMENT FACTORS............................................................. 3-3

TABLE 4-1. BASELINE MAXIMUM 24-HOUR SO2, NOX, AND PM10 EMISSION RATES (AS HOURLY

EQUIVALENTS) ............................................................................................................ 4-2

TABLE 4-2. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-01 BY POLLUTANT ............ 4-3

TABLE 4-3. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-02 BY POLLUTANT ............ 4-4

TABLE 4-4. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-05 BY POLLUTANT ............ 4-5

TABLE 5-1. AVAILABLE SO2 CONTROL TECHNOLOGIES FOR SN-01 AND SN-02 .............................. 5-1

TABLE 5-2. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE SO2 CONTROL

TECHNOLOGIES ........................................................................................................... 5-3

TABLE 5-3. SUMMARY OF COST EFFECTIVENESS FOR SN-01 AND SN-02 SO2 CONTROLS ............... 5-6

TABLE 5-4. SUMMARY OF EMISSION RATES MODELED TO REFLECT SO2 CONTROLS ....................... 5-8

TABLE 5-5 SUMMARY OF MODELED IMPACTS FROM SO2 CONTROL VISIBILITY IMPACT

ANALYSIS FOR SN-01 (2001-2003) ................................................................................ 5-9

TABLE 5-6. SUMMARY OF MODELED IMPACTS FROM SO2 CONTROL VISIBILITY IMPACT

ANALYSIS FOR SN-02 (2001-2003) ............................................................................. 5-10

TABLE 5-7. INCREMENTAL COST EFFECTIVENESS FOR SN-01 WITH CLASS I AREA

IMPROVEMENT ........................................................................................................... 5-12

TABLE 5-8. INCREMENTAL COST EFFECTIVENESS FOR SN-02 WITH CLASS I AREA

IMPROVEMENT ........................................................................................................... 5-12

TABLE 6-1. AVAILABLE NOX CONTROL TECHNOLOGIES FOR SN-01 AND SN-02 ............................ 6-1
Entergy iv Trinity Consultants

BART Analysis – White Bluff

TABLE 6-2. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NOX CONTROL

TECHNOLOGIES ............................................................................................................ 6-5

TABLE 6-3. SUMMARY OF COST EFFECTIVENESS FOR SN-01 AND SN-02 NOX CONTROLS ............... 6-8

TABLE 6-4. SUMMARY OF EMISSION RATES MODELED TO REFLECT NOX CONTROLS.................... 6-11

TABLE 6-5. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL

SYSTEMS ON SN-01 (2001-2003) ................................................................................ 6-12

TABLE 6-6. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL

SYSTEMS ON SN-02 (2001-2003) ............................................................................... 6-13

TABLE 6-7. INCREMENTAL COST EFFECTIVENESS FOR SN-01 WITH CLASS I AREA

IMPROVEMENT ............................................................................................................ 6-15

TABLE 6-8. INCREMENTAL COST EFFECTIVENESS FOR SN-02 WITH CLASS I AREA

IMPROVEMENT ............................................................................................................ 6-15

TABLE B-1. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-01 BY POLLUTANT ........... 7-9

TABLE B-2. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-02 BY POLLUTANT ........... 7-9

TABLE B-3. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-05 BY POLLUTANT ......... 7-10
Entergy 1-1 Trinity Consultants

BART Analysis – White Bluff

1. EXECUTIVE SUMMARY

This report is a revision to “BART Five Factor Analysis” submitted to ADEQ on February 21, 2013,

and revised and resubmitted on June 10, 2013. This report is submitted to provide a comprehensive

document that encompasses the determination of the Best Available Retrofit Technology (BART) for

Entergy Arkansas, Inc.’s (Entergy’s) BART-affected electric generating units (EGUs) at the White

Bluff including changes made in response to EPA’s comments and suggestions on the previous

submittal, which were received by Entergy on March 6 and August 21, 2013. This analysis updates

and replaces the previous June 2013 FFA. The BART determination for each pollutant has not

changed.

Entergy operates three BART-affected EGUs at White Bluff: two coal-fired primary boilers (SN-01

and SN-02) and one fuel oil-fired auxiliary boiler (SN-05). The coal-fired boilers are identical

tangentially-fired boilers with a maximum net power rating of 850 MW each and a nominal heat input

capacity of 8,950 million British thermal units per hour (MMBtu/hr) each. The boilers burn subbituminous or bituminous coal1 as the primary fuel and No. 2 fuel oil or biofuel as a start-up fuel.

SN-01 and SN-02 are currently equipped with electrostatic precipitators (ESPs).

The Auxiliary Boiler, SN-05, is a 183 MMBtu/hr auxiliary boiler burning No. 2 fuel oil or biodiesel

as its only fuel types. The purpose of the Auxiliary Boiler is to provide steam for the start-up of the

two primary boilers, SN-01 and SN-02. There is no emissions control equipment connected to the

Auxiliary Boiler. Typically, the Auxiliary Boiler is only used in the rare instance when both of the

main boilers are not operating.

Based on modeling performed for this analysis, cumulative emissions of nitrogen oxides (NOX),

sulfur dioxide (SO2), and particulate matter with a mass mean diameter smaller than ten microns

(PM10) from SN-01, SN-02, and SN-05 are predicted to cause or contribute greater than 0.5 delta

deciviews ( ̈dv) of visibility impairment in four (4) Class I Areas: Caney Creek Wilderness (CACR),

Upper Buffalo Wilderness (UPBU), Hercules Glades Wilderness (HERC), and Mingo Wilderness

(MING)2, 3. A summary of the modeled visibility impairment attributable to SN-01, SN-02, and SN05 based on default natural conditions is provided in Table 1-1. The visibility impairment

summarized in Table 1-1 is based on modeling conducted by Trinity Consultants (Trinity) using

emissions data based on a combination of continuous emissions monitoring system (CEMS) data as

reported to EPA’s Clean Air Markets Database (CAMD), stack testing, and annual emissions

inventory information as further described in Section 4 of this report.

1 SN-01 and SN-02 primarily burn sub-bituminous coal, but are permitted to burn bituminous or sub-bituminous

coal. Only sub-bituminous coals were burned during the 2001-2003 and 2009-2011 baseline periods evaluated in this

analysis.

2 SN-05 does not cause visibility impairment greater than 0.5 ǻdv in any Class I area but has been reviewed as

part of the BART five factor analysis for the site because total impairment from the combined units is greater than 0.5 ǻdv

in at least one Class I area. See Table 4-4.

3 Sipsey Wilderness was included in the Arkansas Department of Environmental Quality's (ADEQ’s) original

BART analyses, but is not included in this analysis because the EPA-requested change in meteorological data (to a refined,

or "NO OBS = 0", dataset; see Section 3 and Appendix B) excludes Sipsey from the modeling domain.
Entergy 1-2 Trinity Consultants

BART Analysis – White Bluff

TABLE 1-1. MODELED EXISTING VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-01, SN-02 AND

SN-05

CACR UPBU HERC MING

 Source

98th %

 ̈dv

Days

> 0.5

 ̈dv

98th %

 ̈dv

Days

> 0.5

 ̈dv

98th %

 ̈dv

Days

> 0.5

 ̈dv

98th %

 ̈dv

Days

> 0.5

 ̈dv

SN-05 0.010 0 0.005 0 0.004 0 0.008 0

SN-01 1.628 106 1.140 77 1.041 61 0.887 56

SN-02 1.695 112 1.185 80 1.060 65 0.903 57

Trinity used the EPA’s BART guidelines in 40 CFR Part 514 and other recent EPA guidance5 to

determine BART for the boilers. Trinity conducted a five-step analysis to determine BART for SO2

and NOx that included the following:

1. Identifying all available retrofit control technologies;

2. Eliminating technically infeasible control technologies;

3. Evaluating the control effectiveness of remaining control technologies;

4. Evaluating impacts and documenting the results; and

5. Evaluating visibility impacts.

The BART analysis concluded that the installation of a semi-dry FGD system constitutes BART for

SO2 for both SN-01 and SN-02. The proposed BART emission rate for SO2 is 0.06 lb/MMBtu on a

rolling 30-day average. Since baseline visibility modeling showed that there is no opportunity for

visibility improvement attributable to SN-05, because not a single day greater than 0.5  ̈dv is

associated with SN-05, it is not possible to install control equipment to improve visibility. Therefore,

no controls is the SO2 BART determination for SN-05.

The BART analysis concludes that for NOX, the achievement of an emission rate of 0.15 lb/MMBtu

through the installation and use of low NOX burners and separated overfire air (LNB/SOFA)

represents BART for SN-01 and SN-02.6 Based on the same logic outlined above for SO2, NOx

controls are not appropriate or required for SN-05.

4 The BART guidelines were published as amendments to the EPA’s Regional Haze Rule (RHR) in 40 CFR Part

51, Section 308 on July 6, 2005.

5 April 26, 2012, letter from Mr. Guy Donaldson, EPA Region VI, to Mr. Anthony Davis, ADEQ.

6 EPA recently issued a final rule allowing states that are subject to the Cross-State Air Pollution Rule (CSAPR)

trading program for seasonal NOX to rely on the reductions achieved through that trading program to satisfy the regional

haze program requirements for units subject to BART. “Regional Haze: Revisions to Provisions Governing Alternatives to

Source-Specific Best Available Technology (BART) Determinations, Limited SIP Disapprovals and Federal Implementation

Plans,” 77 Fed. Reg. 33651 (June 7, 2012). On August 21, 2012, the D.C. Circuit in a 2-1 decision vacated CSAPR (EME

Homer City Generation v. EPA, --F. 3d --, No. 11-1302 (D.C. Cir. 2012)), and the Clean Air Interstate Rule (CAIR) remains

in effect until a replacement rule, if any, is promulgated. If CSAPR ultimately is upheld and implemented in Arkansas,

Entergy may rely on CSAPR to satisfy its NOx regional haze obligations at SN-01 and SN-02. Alternatively, if CSAPR is

vacated and CAIR remains in place, Entergy may rely on CAIR to satisfy its NOx obligations under BART as EPA has

previously determined that the CAIR season NOx trading program provides greater visibility improvement than BART.
Entergy 1-3 Trinity Consultants

BART Analysis – White Bluff

EPA approved a BART determination for PM10 at SN-01 and SN-02 in its March 12, 2012, final rule

based on the existing ESPs, and established a BART emission rate of 0.1 lb/MMBtu for each boiler.7

7 “Approval and Promulgation of Implementation Plans; Arkansas; Regional Haze State Implementation Plan;

Interstate Transport State Implementation Plan To Address Pollution Affecting Visibility and Regional Haze. Final Rule,”

77 Fed. Reg. 14604 (March 12, 2012).
Entergy 2-1 Trinity Consultants

BART Analysis – White Bluff

2. INTRODUCTION AND BACKGROUND

In the 1977 amendments to the Clean Air Act (CAA), Congress set a national goal to restore national

parks and wilderness areas to pristine conditions by preventing any future, and remedying any

existing, man-made visibility impairment. On July 1, 1999, the U.S. EPA published the final

Regional Haze Rule (RHR). The objective of the RHR is to restore visibility to pristine conditions in

156 specific areas across the United States known as Class I areas. The CAA defines Class I areas as

certain national parks (larger than 6,000 acres), wilderness areas (larger than 5,000 acres), national

memorial parks (larger than 5,000 acres), and international parks that were in existence on August 7,

1977.

The RHR requires States to set goals that provide for reasonable progress towards achieving natural

visibility conditions for each Class I area in their state. On July 6, 2005, the EPA published

amendments to its 1999 RHR, often called the Best Available Retrofit Technology (BART) rule,

which included guidance for making source-specific BART determinations.8 The BART rule defines

BART-eligible sources as sources that meet the following criteria:

1. Have potential emissions of at least 250 tons per year of a visibility-impairing pollutant;

2. Began operation between August 7, 1962 and August 7, 1977; and

3. Are included as one of the 26 listed source categories in the guidance.

A BART-eligible source is subject to BART if the source is “reasonably anticipated to cause or

contribute to visibility impairment in any federal mandatory Class I area.” EPA has determined that a

source is reasonably anticipated to cause or contribute to visibility impairment if the 98th percentile

visibility impacts from the source are modeled to be greater than 0.5 delta deciviews ( ̈dv) when

compared against a natural background.9 Air quality modeling is the tool that is used to determine a

source’s visibility impacts.

Once it is determined that a source is subject to BART, a BART determination must address air

pollution control measures for the source. The visibility regulations define BART as follows:

...an emission limitation based on the degree of reduction achievable through the

application of the best system of continuous emission reduction for each pollutant

which is emitted by...[a BART-eligible source]. The emission limitation must be

established on a case-by-case basis, taking into consideration the technology available,

the cost of compliance, the energy and non air quality environmental impacts of

compliance, any pollution control equipment in use or in existence at the source, the

remaining useful life of the source, and the degree of improvement in visibility which

may reasonably be anticipated to result from the use of such technology.

8 The BART guidelines were published as amendments to the EPA’s RHR in 40 CFR Part 51, Section 308.

9 The original modeling for Arkansas sources relied on screening met data and, as such, reviewed the maximum

impact rather than the 98th percentile impact. Use of the 98th percentile impact based on the use of refined met data (such as

that used in the modeling conducted as part of this BART analysis) is consistent with both the EPA’s 2005 BART rule and

the 2005 Central Regional Air Planning Association (CENRAP) BART modeling guidelines.
Entergy 2-2 Trinity Consultants

BART Analysis – White Bluff

Specifically, the BART rule states that a BART determination should address the following five

statutory factors:

1. Existing controls;

2. Cost of controls;

3. Energy and non-air quality environmental impacts;

4. Remaining useful life of the source; and

5. Degree of visibility improvement as a result of controls.

Further, the BART rule indicates that the five basic steps in a BART analysis can be summarized as

follows:

1. Identify all available retrofit control technologies;

2. Eliminate technically infeasible control technologies;

3. Evaluate the control effectiveness of remaining control technologies;

4. Evaluate impacts and document the results; and

5. Evaluate visibility impacts.

A BART determination should be made for each visibility-affecting pollutant (VAP) by following the

five steps listed above for each VAP.

SN-01 and SN-02 meet the three BART-eligibility criteria described above, and the existing visibility

impairment attributable to each boiler is greater than 0.5  ̈dv in at least one Class I area. Thus, SN01 and SN-02 are subject to BART. SN-05 does not cause visibility impairment greater than 0.5  ̈dv

in any Class I area10 but has been reviewed as part of the BART five factor analysis for the site

because total impairment from the combined units is greater than 0.5  ̈dv in at least one Class I area.

Details of the existing/baseline emissions and the contribution of the emissions to visibility

impairment can be found in Section 4. The VAPs emitted by the boilers include NOX, SO2, and PM10

of various forms (filterable coarse particulate matter [PMc], filterable fine particulate matter [PMf],

elemental carbon [EC], inorganic condensable particulate matter [IOR CPM] as sulfates [SO4], and

organic condensable particulate matter [OR CPM] also referred to as secondary organic aerosols

[SOA]). The BART determinations for SO2, NOX, and PM10 can be found in Sections 5, 6, and 7,

respectively.

10 See Table 4-4.
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3. MODELING METHODOLOGIES AND PROCEDURES

This section summarizes the dispersion modeling methodologies and procedures applied in this

BART analysis. All dispersion modeling has been conducted using the CALPUFF modeling system,

consisting of the CALPUFF dispersion model, the CALMET meteorological data processor, and the

CALPOST post-processing program. These methodologies and procedures are consistent with the

ADEQ modeling protocol submitted to EPA in June 2012.

CALPUFF is a multi-layer, multi-species, non-steady-state puff dispersion model, which can simulate

the effects of time and space varying meteorological conditions on pollutant transport, transformation,

and removal. CALPUFF uses three-dimensional meteorological fields developed by the CALMET

model. In addition to meteorological data, several other input files are used by the CALPUFF model

to specify source and receptor parameters. The selection and control of CALPUFF options are

determined by user-specific inputs contained in the control file. This file contains all of the necessary

information to define a model run (e.g., starting date, run length, grid specifications, technical

options, output options). CALPOST processes concentration, deposition, and visibility impacts based

on pollutant specific concentrations predicted by CALPUFF.

3.1 CALMET AND CALPUFF

The CALPUFF data and parameters are based on the 2005 BART modeling guidelines prepared for

CENRAP. The CALMET data and parameters are based on the modeling protocol included in

Appendix B. Note that the protocol included in Appendix B summarizes modeling methods and

procedures that were followed to predict visibility impairment as part of the BART analyses for

several BART-eligible sources located in Oklahoma, the first of which was Oklahoma Gas & Electric

in 2007. The CALMET dataset developed per this protocol has been used – and approved by EPA –

numerous times since its development.

3.2 CALPOST

The CALPOST visibility processing completed for this BART analysis is based on the October 2010

guidance from the Federal Land Managers Air Quality Related Values Workgroup (FLAG).11

Visibility impairment is quantified using the light extinction coefficient (bext), which is expressed in

terms of the haze index expressed in deciviews (dv). The haze index (HI) is calculated as follows:

 ̧

1

·

 ̈

©

§

 

10

(dv) 10 ln ext b

HI

The impact of a source is determined by comparing the HI attributable to a source relative to

estimated natural background conditions. The change in the haze index, in deciviews, also referred to

11 The 2010 FLAG guidance, which was issued in draft form on July 8, 2008, and published as final guidance in

December 2010, makes technical revisions to the previous guidance issued in December 2000.
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as “delta dv,” or  ̈dv, based on the source and background light extinction is based on the following

equation:

' dv = 10*ln

b b

b

ext, background ext, source

ext, background

a 

¬

«

«

o

1⁄4

»

»

The Interagency Monitoring of Protected Visual Environments (IMPROVE) workgroup adopted an

equation for predicting light extinction as part of the 2010 FLAG guidance (often referred to as the

new IMPROVE equation). The new IMPROVE equation is as follows:

bext 

 >   @  >   @

 > @  > @

> @ > @ > @> @ > @

 > @ > @ Site specific Rayleigh Scattering 2

Small Large

4 3 Small 4 3 Large

4 4 2 Small 4 4 2 Large

1.4 Sea Salt 0.33 NO

2.8 OC 6.1 OC 10 EC 1 PMF 0.6 PMC

2.4 NH NO 5.1 NH NO

2.2 NH SO 4.8 NH SO

 

    

 

 

RH b f

f RH f RH

f RH f RH

SS

S L

S L

Visibility impairment predictions relied upon in this BART analysis used the equation shown above.

The use of this equation is referred to as “Method 8” in the CALPOST control file. The use of

Method 8 requires that one of five different “modes” be selected. The modes specify the approach for

addressing the growth of hygroscopic particles due to moisture in the atmosphere. “Mode 5” has

been used in this BART analysis. Mode 5 addresses moisture in the atmosphere in a similar way as to

“Method 6”, where “Method 6” is specified as the preferred approach for use with the old IMPROVE

equation in the CENRAP BART modeling protocol.

CALPOST Method 8, Mode 5 requires the following:

x Annual average concentrations reflecting natural background for various particles and for sea

salt

x Monthly Relative Humidity (RH) adjustment factors for large and small ammonium sulfates

and nitrates and for sea salts

x Rayleigh scattering parameter corrected for site-specific elevation

Tables 3-1 to Table 3-4 below show the values for the data described above that were input to

CALPOST for use with Method 8, Mode 5. The values were obtained from the 2010 FLAG

guidance.
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TABLE 3-1. ANNUAL AVERAGE BACKGROUND CONCENTRATION

Class I Area

(NH4)2SO4

(μg/m3)

NH4NO3

(μg/m3)

OM

(μg/m3)

EC

(μg/m3)

Soil

(μg/m3)

CM

(μg/m3)

Sea Salt

(μg/m3)

Rayleigh

(Mm-1)

CACR 0.23 0.1 1.8 0.02 0.5 3 0.03 11

UPBU 0.23 0.1 1.8 0.02 0.5 3 0.03 11

HERC 0.23 0.1 1.8 0.02 0.5 3 0.02 11

MING 0.23 0.1 1.83 0.02 0.51 3.05 0.04 12

TABLE 3-2. FL(RH) LARGE RH ADJUSTMENT FACTORS

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

CACR 2.77 2.53 2.37 2.43 2.68 2.71 2.59 2.6 2.71 2.69 2.67 2.79

UPBU 2.71 2.48 2.31 2.33 2.61 2.64 2.57 2.59 2.71 2.58 2.59 2.72

HERC 2.7 2.48 2.3 2.3 2.57 2.59 2.56 2.6 2.69 2.54 2.57 2.72

MING 2.73 2.52 2.34 2.28 2.53 2.6 2.64 2.67 2.71 2.56 2.56 2.73

TABLE 3-3. FS(RH) SMALL RH ADJUSTMENT FACTORS

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

CACR 3.85 3.44 3.14 3.24 3.66 3.71 3.49 3.51 3.73 3.72 3.68 3.88

UPBU 3.73 3.33 3.03 3.07 3.54 3.57 3.43 3.5 3.71 3.51 3.52 3.74

HERC 3.7 3.33 3.01 3.01 3.47 3.48 3.41 3.51 3.67 3.43 3.46 3.73

MING 3.74 3.38 3.07 2.97 3.39 3.52 3.57 3.64 3.72 3.47 3.43 3.74

TABLE 3-4. FSS(RH) SEA SALT RH ADJUSTMENT FACTORS

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

CACR 3.9 3.52 3.31 3.41 3.83 3.88 3.69 3.68 3.82 3.76 3.77 3.93

UPBU 3.85 3.47 3.23 3.27 3.72 3.78 3.69 3.7 3.84 3.64 3.67 3.86

HERC 3.86 3.51 3.23 3.22 3.66 3.72 3.69 3.73 3.81 3.57 3.65 3.88

MING 3.92 3.58 3.3 3.19 3.58 3.72 3.8 3.82 3.85 3.61 3.66 3.9
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4. EXISTING EMISSIONS AND VISIBILITY IMPAIRMENT

This section summarizes the existing (i.e., baseline) visibility based on air quality modeling

conducted by Trinity.

4.1 NOX, SO2, AND PM10 BASELINE EMISSION RATES

Table 4-1 summarizes the emission rates that were modeled for SO2, NOX, and PM10, including the

speciated PM10 emissions. The SO2 and NOX emission rates are the highest actual 24-hour emission

rates based on CAMD data from 2001-2003 for SO2 and from 2009-2011 for NOX

12. The 2001-2003

period was not used for NOX because that period no longer represents actual operation of the boilers.

In 2006, Entergy completed the addition of a neural net system and also conducted extensive boiler

tuning. These projects substantially reduced NOX emissions. Accordingly, there is a real difference

in operations/emissions between the original baseline period (2001-2003) and current operations such

that the 2001-2003 time period is not representative of current (and thus future, post-BART)

operations. The BART regulation, at 40 CFR Part 51, Appendix Y, Section IV.D.4.c, speaks to this

issue:

The baseline emissions rate should represent a realistic depiction of anticipated annual

emissions for the source. In general, for the existing sources subject to BART, you will

estimate the anticipated annual emissions based upon actual emissions from a baseline

period. When you project that future operating parameters (e.g., limited hours of operation

or capacity utilization, type of fuel, raw materials or product mix or type) will differ from

past practice, and if this projection has a deciding effect in the BART determination, then you

must make these parameters or assumptions into enforceable limitations. In the absence of

enforceable limitations, you calculate baseline emissions based upon continuation of past

practice.

Using the emission rates from 2001-2003 for NOX would over-state the emissions reductions from the

proposed BART control technology. Moreover, using the 2001-2003 NOX emission rates would

exaggerate the projected visibility improvement in the Class I areas. Thus, updating the NOX

emission rates to represent current, normal operation better comports with the regulations. Entergy

submitted a determination request to ADEQ on August 23, 2012, to use the 2009-2011 NOX emission

rates based on CEMS data. ADEQ and EPA determined that using the 2009-2011 NOX emission

rates is consistent with the BART guidance13.

The PM10 emission rates are based on emission factors from AP-42 for PM10 filterable and PM

condensable with a 99.5% control efficiency for ESP applied to the PM10 filterable in conjunction

with the average coal heat value and average coal % ash from 2009-2011. The emission rates for the

PM10 species reflect the breakdown of the PM10 determined from the National Park Service (NPS)

12 See Appendix D.

13 See Email, dated September 10, 2012, from Guy Donaldson (EPA, Region VI) to Mary Pettyjohn (ADEQ).
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“speciation spreadsheet” for Dry Bottom Boiler Burning Pulverized Coal using only ESP.14 More

specifically, the NPS workbook shows the following baseline distribution for the PM species:

Ÿ Coarse PM (PMC) = 33.6%

Ÿ Fine soil (modeled as PMF) = 25.9%

Ÿ Fine elemental carbon (modeled as EC) = 1.0 %

Ÿ Organic condensable PM (modeled as SOA) = 7.9%

Ÿ Inorganic condensable PM (modeled as SO4) = 31.6%

TABLE 4-1. BASELINE MAXIMUM 24-HOUR SO2, NOX, AND PM10 EMISSION RATES (AS HOURLY

EQUIVALENTS)

SO2

15 NOX

16

Total

PM10 SO4 PMc PMf SOA EC

Source (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr)

SN-05 5.8 31.7 2.8 0.9 0.5 1.2 0.2 0.1

SN-01 7,763.5 3,001.4 118.6 36.8 40.4 31.1 9.2 1.2

SN-02 7,825.1 3,527.4 118.6 36.8 40.4 31.1 9.2 1.2

4.2 BASELINE VISIBILITY IMPAIRMENT

Trinity conducted modeling to estimate the current visibility impairment attributable to SN-01, SN02, and SN-05 in four Class I Areas: Caney Creek Wilderness (CACR), Upper Buffalo Wilderness

(UPBU), Hercules Glades Wilderness (HERC), and Mingo Wilderness (MING) using the CALPUFF

dispersion model.17 Table 4-2, Table 4-3, and Table 4-4 provide a summary of the modeled visibility

impairment attributable to SN-01, SN-02, and SN-05 respectively, based on the emission rates shown

in Table 4-1. These tables show the maximum impairment in ǻdv, the 98th percentile impacts in ǻdv,

and the number of days with impacts greater than 0.5 ǻdv as well as the breakdown by pollutant

species for the 98th percentile impact.

As BART is determined on a unit-by-unit basis, this baseline modeling is presented to show how the

BART proposed controls will cause improvement, at least on a relative basis.

All of the CALMET, CALPUFF, and CALPOST modeling files used to generate these results are

included as part of the electronic files submitted with this document.

14 The NPS Workbook, "PC Dry Bottom ESP Example.xls" updated 03/2006, was obtained from the NPS

website: http://www.nature.nps.gov/air/Permits/ect/index.cfm. The following parameters were input into the workbook for

speciation determination: total PM10 emission rate of 118.6 lb/hr, heat value of 8,950 Btu/lb, sulfur content of 0.27% and,

ash content of 4.87%.

15 The SO2 hourly rates were derived from EPA’s CAMD data for 2001 - 2003. The 2001-2003 max daily rates

were 183,324 lb/day and 187,802 lb/day for SN-01 and SN-02, respectively. See Appendix D.

16 The NOX hourly rates were derived from EPA’s CAMD data for 2009-2011. The 2001-2003 max daily rates

were 72,034 lb/day and 84,658 lb/day for SN-01 and SN-02, respectively. See Appendix D.

17 Due to an EPA-requested change in meteorological data which excluded Sipsey Class 1 Area from the

modeling domain, Sipsey was not included in this analysis. See footnote 1, above.
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TABLE 4-2. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-01 BY POLLUTANT

Year

98th

Percentile

No. of

Day

with

ǻdv 

0.5

98th

Percentile

98th

Percentile

98th

Percentile

98th

Percentile

Maximum ǻdv) ǻdv SO4 ǻdv NO3 ǻdv PM10 ǻdv NO2

ǻdv)

Caney Creek Wilderness

2001 2.956 1.628 41 1.287 0.336 0.003 0.002

2002 2.111 1.386 30 0.662 0.659 0.011 0.054

2003 4.194 1.130 35 0.722 0.385 0.003 0.020

Upper Buffalo Wilderness

2001 2.339 1.128 34 0.835 0.290 0.003 0.000

2002 1.544 0.818 18 0.680 0.133 0.003 0.002

2003 1.900 1.140 25 1.117 0.021 0.003 0.000

Hercules Glades Wilderness

2001 1.737 1.041 28 0.961 0.078 0.002 0.000

2002 1.288 0.617 13 0.487 0.128 0.001 0.000

2003 2.230 0.786 20 0.699 0.085 0.002 0.000

Mingo Wilderness

2001 1.569 0.887 18 0.828 0.053 0.003 0.002

2002 1.012 0.750 24 0.427 0.319 0.002 0.002

2003 1.114 0.702 14 0.448 0.245 0.003 0.007

Table 4-2 demonstrates that the 98th percentile impacts from SO4 are always greater than the 98th

percentile impacts from NO3. Therefore, SO4, and by default SO2, is clearly the dominating pollutant

of concern from SN-01.
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TABLE 4-3. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-02 BY POLLUTANT

Year

98th

Percentile

No. of

Day

with

ǻdv 

0.5

98th

Percentile

98th

Percentile

98th

Percentile

98th

Percentile

Maximum ǻdv) ǻdv SO4 ǻdv NO3 ǻdv PM10 ǻdv NO2

ǻdv)

Caney Creek Wilderness

2001 3.199 1.695 41 1.292 0.398 0.003 0.002

2002 2.270 1.481 33 0.964 0.465 0.011 0.041

2003 4.437 1.169 38 0.595 0.555 0.004 0.015

Upper Buffalo Wilderness

2001 2.385 1.185 35 0.840 0.343 0.003 0.000

2002 1.618 0.846 20 0.685 0.156 0.003 0.003

2003 1.998 1.176 25 0.958 0.215 0.003 0.000

Hercules Glades Wilderness

2001 1.838 1.060 30 0.966 0.092 0.002 0.000

2002 1.340 0.643 14 0.490 0.151 0.001 0.001

2003 2.263 0.806 21 0.703 0.101 0.002 0.000

Mingo Wilderness

2001 1.701 0.903 18 0.834 0.063 0.003 0.003

2002 1.031 0.805 25 0.674 0.129 0.002 0.000

2003 1.150 0.750 14 0.452 0.288 0.003 0.008

Table 4-3 demonstrates that the 98th percentile impacts from SO4 are always greater than the 98th

percentile impacts from NO3. Therefore, as with SN-01, SO4, and by default SO2, is clearly the

dominating pollutant of concern from SN-02.
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TABLE 4-4. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-05 BY POLLUTANT

Year

Maximum

ǻdv)

98th

Percentile

ǻdv)

No. of

Day with

ǻdv  0.5

98th

Percentile

ǻdv SO4

98th

Percentile

ǻdv NO3

98th

Percentile

ǻdv PM10

98th

Percentile

ǻdv NO2

Caney Creek Wilderness

2001 0.028 0.008 0 0.001 0.007 0.000 0.000

2002 0.02 0.005 0 0.001 0.004 0.000 0.000

2003 0.036 0.01 0 0.002 0.008 0.000 0.000

Upper Buffalo Wilderness

2001 0.014 0.004 0 0.001 0.003 0.000 0.000

2002 0.009 0.004 0 0.003 0.000 0.000 0.000

2003 0.013 0.005 0 0.001 0.004 0.000 0.000

Hercules Glades Wilderness

2001 0.007 0.004 0 0.001 0.003 0.000 0.000

2002 0.006 0.003 0 0.001 0.002 0.000 0.000

2003 0.008 0.004 0 0.002 0.001 0.000 0.000

Mingo Wilderness

2001 0.009 0.003 0 0.000 0.003 0.000 0.000

2002 0.019 0.008 0 0.001 0.007 0.000 0.000

2003 0.015 0.003 0 0.001 0.002 0.000 0.000

Table 4-4 demonstrates that the 98th percentile impacts from the combined pollutants are well below

the 0.5 ǻdv threshold to be considered a contributor to visibility impairment.
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5. SO2 BART EVALUATION

5.1 IDENTIFICATION OF AVAILABLE RETROFIT SO2 CONTROL

TECHNOLOGIES FOR SN-01 AND SN-02

Sulfur oxides, SOX, are generated during coal combustion from the oxidation of sulfur contained in

the fuel. SOX emissions are almost entirely dependent on the sulfur content of the fuel and are

generally not affected by boiler size or burner design. SOX emissions from conventional combustion

systems are predominantly in the form of SO2. Since SO2 is the predominant sulfur compound

emitted from SN-01 and SN-02, the BART analysis is specific to emissions of SO2. Reductions in

emissions of SO2 will reduce visibility impairment by reducing sulfate (SO4) formation.

Step 1 of the top-down control review is to identify available retrofit control options for SO2. The

available SO2 retrofit control technologies for SN-01 and SN-02 are summarized in Table 5-1. The

retrofit controls examined are limited to add-on controls that eliminate SO2 after it is formed, as SN01 and SN-02 currently use a low sulfur fuel and thus would not achieve significant additional

reductions through alternative fuel supplies comparable to the most efficient add-on controls. The

available SO2 control technologies are Dry Sorbent Injection (DSI), semi-dry scrubbing, and wet

scrubbing.

TABLE 5-1. AVAILABLE SO2 CONTROL TECHNOLOGIES FOR SN-01 AND SN-02

SO2 Control Technologies

Dry Sorbent Injection

Semi-Dry Scrubbing

 Wet Scrubbing

5.2 ELIMINATE TECHNICALLY INFEASIBLE SO2 CONTROL TECHNOLOGIES

FOR SN-01 AND SN-02

Step 2 of the BART determination is to eliminate technically infeasible SO2 control technologies that

were identified in Step 1.

5.2.1 DRY SORBENT INJECTION

Dry sorbent injection involves the injection of a sorbent into the exhaust gas stream where

SO2 reacts with and becomes entrained in the sorbent. The stream is then passed through a

particulate control device to remove the sorbent and entrained SO2. The process was

developed as a lower cost Flue Gas Desulfurization (FGD) option because the mixing of

the SO2 and sorbent occurs directly in the exhaust gas stream instead of in a separate tower.

Depending on the residence time, gas stream temperature, and limitations of the particulate
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control device, sorbent injection control efficiency can range between 40 and 60 percent.18

This control is a technically feasible option for the control of SO2 from SN-01 and SN-02.

5.2.2 SEMI-DRY SCRUBBER

There are various designs of semi-dry scrubbing; or fuel gas desulfurization (FGD);

systems, including the Spray Dryer Absorber (SDA) and Circulating Dry Scrubber (CDS)

designs. In the SDA design, a fine mist of lime slurry is sprayed into an absorption tower

where the SO2 is absorbed by the slurry droplets. The absorption of the SO2 leads to the

formation of calcium sulfite and calcium sulfate within the droplets. The liquid-to-gas

ratio is such that the heat from the exhaust gas causes the water to evaporate before the

droplets reach the bottom of the tower. This leads to the formation of a dry powder which

is carried out with the gas and collected with a fabric filter.

In the CDS process, the flue gas is introduced into the bottom of a reactor vessel at high

velocity through a venturi nozzle; the exhaust is mixed with water, hydrated lime, recycled

flyash and CDS reaction products. The intensive gas-solid mixing that occurs in the

reactor promotes the reaction of sulfur oxides in the flue gas with the dry lime particles.

The mixture of reaction products (calcium sulfite/sulfate), unreacted lime, and fly ash is

carried out with the exhaust and collected in an ESP or fabric filter. A large portion of the

collected particles is recycled to the reactor to sustain the bed and improve lime utilization.

Semi-dry scrubbing control efficiencies range from 60 to 95 percent,19 and is a technically

feasible option for the control of SO2 from SN-01 and SN-02.

5.2.3 WET SCRUBBER

Wet scrubbing involves scrubbing the exhaust gas stream with slurry comprised of lime or

limestone in suspension. The process takes place in a wet scrubbing tower located

downstream of a PM control device such as a fabric filter or an electrostatic precipitator

(ESP) to prevent the plugging of spray nozzles and other problems caused by the presence

of particulates in the scrubber. Similar to the chemistry illustrated above for spray dryer

absorption, the SO2 in the gas stream reacts with the lime or limestone slurry to form

calcium sulfite and calcium sulfate. Wet lime scrubbing is generally capable of achieving

80-95 percent control.20 Higher control efficiencies may be achieved in certain

applications. This control is a technically feasible option for the control of SO2 from SN01 and SN-02.

18 "Assessment of Control Technology Options for BART-Eligible Sources: Steam Electric Boilers, Industrial

Boilers, Cement Plants and Paper and Pulp Facilities" Northeast States for Coordinated Air Use Management (NESCAUM),

March 2005.

19 EPA Basic Concepts in Environmental Sciences, Module 6: Air Pollutants and Control Techniques

http://www.epa.gov/eogapti1/module6/sulfur/control/control.htm

20 Id.
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EPA has recently suggested the control from wet scrubbing can achieve emissions

reductions of up to 97%. Engineering evaluations conducted on Unit 1 and 2 by Sargent &

Lundy (S&L) suggest that a control efficiency of up to 97% may be achievable through the

application of wet scrubbing for higher-sulfur coals. However, as no vendor guarantee for

greater than 95% control from wet scrubbing was available, Entergy cannot confidently

rely on this level of control specific to SN-01 and SN-02. Moreover, Entergy has not

received any assurances from vendors or its engineering consultant, S&L, of achieving

such a level on a consistent, 30-day average basis.

5.3 RANK OF TECHNICALLY FEASIBLE SO2 CONTROL OPTIONS BY

EFFECTIVENESS FOR SN-01 AND SN-02

The third step in the BART analysis is to rank the technically feasible options according to their

effectiveness in reducing the VAP. Table 5-2 provides a ranking of the control levels for the controls

listed in the previous section.

TABLE 5-2. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE SO2 CONTROL

TECHNOLOGIES

Control Technology Estimated Control

Efficiency

Wet Scrubber 80-95%21

Semi-Dry Scrubber 60-95%

Dry Sorbent Injection 40-60%

5.4 EVALUATION OF IMPACTS FOR FEASIBLE SO2 CONTROLS FOR SN-01 AND

SN-02

The fourth step in the BART analysis is the impact analysis where the impacts for those control

options deemed feasible in Step 2 are evaluated. This analysis is typically conducted to demonstrate

that a control technology that is more effective than another technology does not constitute BART.

The BART determination guidelines list the four factors to be considered in the impact analysis:

Ÿ Cost of compliance

Ÿ Energy impacts

Ÿ Non-air quality impacts; and

Ÿ The remaining useful life of the source

Wet and dry scrubbing are the most effective technologies at reducing SO2. As shown in Table 5-2,

both technologies can achieve 95 percent reduction in SO2.

21 Estimated efficiency for wet FGD for low-sulfur coals typically combusted at White Bluff. Higher efficiencies

are achievable for wet FGD when burning higher-sulfur coal, but may not be achievable for the low-sulfur coal typically

combusted at SN-01 and SN-02.
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Site-specific specifications from S&L indicate that semi-dry scrubbing can achieve an outlet rate of

0.06 lb/MMBtu on a 30-day rolling average basis. Entergy believes that semi-dry scrubbing

represents a superior technology in comparison to wet scrubbing, thus the majority of research for this

analysis has been focused on this control option. Information from S&L also indicate that wet

scrubbing may be able to achieve an outlet rate of 0.04 lb/MMBtu on a 30-day rolling average

basis.22 These emission levels represent reductions of 95% for semi-dry scrubbing and 97% for wet

scrubbing when applied to the facility’s current maximum allowable SO2 emission rate of 1.2

lb/MMBtu. Notwithstanding a lack of vendor assurances, for the purposes of this analysis, wet

scrubbing has been evaluated at an outlet SO2 emission rate of 0.04 lb/MMBtu.

5.4.1 COST OF COMPLIANCE

Control Costs

The capital costs were annualized over a 30-year period and then added to the annual

operating costs to obtain the total annualized costs. The details of the cost effectiveness

calculations are provided in Appendix A of this report.

The capital and direct operating and maintenance (O&M) costs of a semi-dry scrubber used

in the cost effectiveness calculations were based on vendor estimates. The indirect

operating costs such as property tax and insurance are based on calculation methods

published in the sixth edition of the EPA’s Air Pollution Cost Control Manual for wet acid

gas absorber systems. The capital and O&M costs of a wet scrubber used in the cost

effectiveness calculations are based on vendor estimates for a system estimated to achieve

97% control for an inlet SO2 rate of 2.0 lb/MMBtu (0.06 lb/MMBtu) and calculation

methods published in the sixth edition of the EPA’s Air Pollution Cost Control Manual.

The costs for a system capable of achieving equivalent control with an inlet SO2 rate of 1.2

lb/MMBtu or 0.04 lb/MMBtuwould be approximately 5 to 6 percent higher. The capital

cost associated with a wet scrubber system is considerably higher than for a semi-dry

scrubber system.

It should be noted that the capital costs presented for the SO2 control options do not include

any Allowance for Funds Used During Construction (AFUDC). AFUDC represents the

interest expense incurred on the investment in a large capital project, such as a scrubber

installation, which can take several years to complete. While interest expenses will

certainly be incurred on a such a project, and AFUDC is typically considered as part of the

capital cost of such a project for standard accounting and rate-making purposes, EPA

Region 6 has expressed concern with the inclusion of this expense. In order to facilitate

timely review of this revised FFA, Entergy, without waiver, has omitted this cost from the

capital costs presented within this FFA.

22 The cost estimate from S&L for a wet FGD system represents a system estimated to achieve 97% control for an

inlet SO2 rate of 2.0 lb/MMBtu (0.06 lb/MMBtu) S&L has indicated the cost for a system capable of achieving 97% control

for an inlet SO2 rate of 1.2 lb/MMBtu (0.04 lb/MMBtu) would be 5 to 6 percent higher. Entergy has not received any

guarantee that an outlet SO2 emission rate of 0.04 lb/MMBtu is consistently achievable for SN-01 or SN-02.
Entergy 5-5 Trinity Consultants

BART Analysis – White Bluff

Annual Tons Reduced

The annual tons reduced that were used in the cost effectiveness calculations were

determined by subtracting the estimated controlled annual emission rate from the baseline

annual emission rate. The baseline annual emission rate was the average rate from 2001-

2003, as reported by Entergy in their air emission inventories. The controlled annual

emission rates were based on the lb/MMBtu levels believed to be achievable for the control

technologies multiplied by the future annual heat input. The future annual heat input is

based on the average hourly heat input from CAMD for 2001 to 2003 multiplied by the

average annual operating hours from 2001-2003 for each boiler.

Cost Effectiveness

The cost effectiveness in dollars per ton of SO2 reduced was determined by dividing the

annualized cost of control by the annual tons reduced. Table 5-3 indicates that the cost

effectiveness of semi-dry scrubber at an SO2 rate of 0.06 lb/MMBtu is approximately

$2,913 per ton of SO2 removed for SN-01 and $3,355 per ton of SO2 removed for SN-02.

The incremental costs for wet scrubbing at 0.04 lb/MMBtu over semi-dry scrubbing at 0.06

lb/MMBtu are $26,701/ton for SN-01 and $27,218/ton for SN-02. As documented in

Section 5.5 below, the additional cost of wet FGD is not justified in light of the negligible

improvement in visibility impacts associated with this control technology.
Entergy 5-6 Trinity Consultants

BART Analysis – White Bluff

TABLE 5-3. SUMMARY OF COST EFFECTIVENESS FOR SN-01 AND SN-02 SO2 CONTROLS

Baseline

Emission

Rate

Controlled

Emission

Level

Annual Heat

Input1

Controlled

Emission

Rate

SO2

Reduced Capital Cost

Annual Capital

Cost

Annual Direct

O&M

Annual

Indirect O&M

Total Annual

Cost

Cost

Effectiveness

Incremental

Cost

Compared to

Semi-Dry

Scrubbing

Incremental

Visibility

Improvement2

(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (tpy) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton) (dv)

SN-01 -Semi-Dry

Scrubbing 19,550 0.06 55,269,197 1,658 17,892 335,133,908 27,007,236 8,837,861 16,282,987 52,128,084 2,913 - 0.813

SN-02 - Semi-Dry

Scrubbing 17,167 0.06 54,138,841 1,624 15,543 335,133,908 27,007,236 8,859,823 16,282,987 52,150,047 3,355 - 0.767

SN-01 -Wet

Scrubbing 19,550 0.04 55,269,197 1,105 18,445 389,496,052 31,388,086 15,946,729 19,550,719 66,885,535 3,626 26,701 0.021

SN-02 - Wet

Scrubbing 17,167 0.04 54,138,841 1,083 16,084 389,496,052 31,388,086 15,946,729 19,550,719 66,885,535 4,158 27,218 0.021

2. The incremental visibility improvement for semi-dry scrubbing is the maximum visibility improvement in the 98th percentile impact compared to baseline (See Tables 5-5 and 5-6). The incremental visibility improvement for

wet scrubbing is the difference between the maximum improvement due to wet scrubbing less the maximum visibility improvement from dry scrubbing (See Tables 5-5 and 5-6).

1. The future annual heat input was estimated by multiplying the average hourly heat input from CAMD for 2009-2011 for each boiler by the average number of operating hours for each boiler from 2009-2011.
Entergy 5-7 Trinity Consultants

BART Analysis – White Bluff

5.4.2 ENERGY IMPACTS AND NON-AIR QUALITY IMPACTS

As illustrated in Table 5-3 and in Section 5.5 below, wet scrubbing is expected to achieve

approximately the same level of visibility improvement as the proposed dry scrubbing

technology. However, the negative non-air quality environmental impacts are greater with

wet scrubbing systems. Such impacts include a potential increase in particulate and

sulfuric acid (H2SO4) mist emissions. In addition, wet scrubbers require increased water

use and generate large volumes of wastewater and solid waste/sludge that must be

managed and/or treated. This places additional burdens on the wastewater treatment and

solid waste management capabilities. Moreover, if wet scrubbing produces calcium sulfite

sludge, the sludge will be water-laden, and it must be stabilized for landfilling. Wet

scrubbing systems require increased power requirements and increased reagent usage over

dry scrubbers. Thus, from an overall environmental perspective, dry scrubbing is superior

to wet scrubbing.

5.4.3 REMAINING USEFUL LIFE

The remaining useful life of SN-01 and SN-02 does not impact the annualized capital costs

for either semi-dry scrubbing or wet scrubbing because the useful life of the units is

anticipated to be at least as long as the capital cost recovery period, which is 30 years based

on the recovery period documented for wet scrubbers for acid gas in the EPA’s Control

Cost Manual.

5.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE SO2 CONTROLS FOR

SN-01 AND SN-02

A final impact analysis was conducted to assess the visibility improvement achieved by comparing

the impacts associated with the baseline emission rates to the impacts associated with the controlled

emission rates. Section 4 of this report documents the existing visibility impairment attributable to

SN-01 and SN-02. In order to assess the visibility improvement associated with semi-dry and wet

scrubbing, the controlled emission rates associated with each control technology were modeled using

CALPUFF. The SO2 emission rates associated with wet and semi-dry scrubbers were calculated as

follows:

P* HI = 537.00 lb/hr

Where:

P for wet scrubber = 0.04 lb/MMBtu

P for semi-dry scrubber = 0.06 lb/MMBtu

HI (hourly heat input) = 8,950 MMBtu/hr

Table 5-4 summarizes the lb/hr emission rates that were modeled to reflect the addition of wet and

semi-dry scrubbers on SN-01 and SN-02. One important thing to note is the ammonium sulfate

emission rate indicated for wet scrubbers is higher than the ammonium sulfate emission rate indicated

for semi-dry scrubbers. For all PM species other than ammonium sulfate, the NPS speciation

spreadsheets were relied upon to determine emission rates for PM species. For ammonium sulfate,

the approach described below was used. The NOX emission rates were modeled at the baseline rates.
Entergy 5-8 Trinity Consultants

BART Analysis – White Bluff

Sulfur in the fuel reacts with oxygen during the combustion process to form SO2. Some of the SO2 is

further oxidized to SO3, which is a precursor to sulfuric acid (H2SO4). Sulfuric acid can react with

ammonia to cause primary emissions of ammonium sulfate. According to both FGD suppliers and

the EPA, wet scrubbers have less affinity for SO3 and typically capture between 25-50% of the SO3.

23

Since SO3 can lead to the formation of H2SO4, which leads to the formation of ammonium sulfates,

the higher level of SO3 control for semi-dry scrubbers will result in lower H2SO4 emissions and thus

lower ammonium sulfate emissions. The ammonium sulfate emission rates for semi-dry scrubbers

shown in Table 5-4 were determined assuming the reduction in ammonium sulfate (SO4) is

proportional to the reduction in SO2 from the baseline case to the controlled case (95%). The

ammonium sulfate emission rates for wet scrubbers shown in Table 5-4 were determined assuming a

50% reduction in SO4 from the baseline case to the controlled case.

TABLE 5-4. SUMMARY OF EMISSION RATES MODELED TO REFLECT SO2 CONTROLS

 Source

SO2

(lb/hr)

SO4

1

(lb/hr)

NOX

(lb/hr)

PMC

(lb/hr)

PMF

(lb/hr)

SOA

(lb/hr)

EC

(lb/hr)

PM10, total

(lb/hr)

SN-01 –

Semi-Dry

Scrubbing 537.0 2.7 3,001.4 1.0 1.0 0.7 0.0 5.4

SN-02 –

Semi-Dry

Scrubbing 537.0 2.8 3,527.4 1.0 1.0 0.7 0.0 5.6

SN-01 – Wet

Scrubbing 358.0 18.4 3,001.4 6.7 6.5 4.6 0.2 36.4

SN-02 – Wet

Scrubbing 358.0 18.4 3,527.4 6.7 6.5 4.6 0.2 36.4

1

SO4 as it is displayed in this table represents ammonium sulfate.

Comparisons of the existing visibility impacts and the visibility impacts based on wet and semi-dry

scrubbing, including the maximum modeled visibility impact, 98th percentile modeled visibility

impact, and the number of days with a modeled visibility impact greater than 0.5 ǻdv, for each Class

I area are provided in Table 5-5 and Table 5-6.

23 In addition, according to the EPA Technical Support Document for the Rules to Reduce Interstate Transport of

Fine Particulate Matter and Ozone, “More than 90 percent of SO3/H2SO4 is removed in a dry FGD, while up to about 50

percent removal occurs in a wet FGD system.” http://www.epa.gov/cair/pdfs/0053-2263.pdf
Entergy 5-9 Trinity Consultants

BART Analysis – White Bluff

TABLE 5-5 SUMMARY OF MODELED IMPACTS FROM SO2 CONTROL VISIBILITY IMPACT ANALYSIS FOR SN-01 (2001-2003)

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR

M

a

xim

u

m

Im

p

act (ǻ

d

v)

98% Im

p

act

(ǻ

d

v)

#

D

a

ys >

0.5

ǻ

d

v

M

a

xim

u

m

Im

p

act (ǻ

d

v)

98% Im

p

act

(ǻ

d

v)

#

D

a

ys >

0.5

ǻ

d

v

M

a

xim

u

m

Im

p

act (ǻ

d

v)

98% Im

p

act

(ǻ

d

v)

#

D

a

ys >

0.5

ǻ

d

v

M

a

xim

u

m

Im

p

act (ǻ

d

v)

98% Im

p

act

(ǻ

d

v)

#

D

a

ys >

0.5

ǻ

d

v

Existing Emission

Rate

4.194 1.628 106 2.339 1.140 77 2.230 1.041 61 1.569 0.887 56

Semi-Dry

Scrubber

1.961 0.815 27 0.763 0.378 6 0.698 0.358 5 0.841 0.267 2

Post Control

Improvement†

2.233 0.813 79 1.576 0.762 71 1.532 0.683 56 0.728 0.620 54

Wet Scrubber 1.941 0.794 26 0.774 0.350 6 0.687 0.360 3 0.838 0.271 1

Incremental

Improvement

over Semi-Dry

Scrubber†

0.020 0.021 1 -0.011 0.028 0 0.011 -0.002 2 0.003 -0.004 1

†The visibility improvement shown in the table has been calculated from values that include more decimal places than what is shown in the table. Due to rounding, the visibility

improvement calculated from the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.
Entergy 5-10 Trinity Consultants

BART Analysis – White Bluff

TABLE 5-6. SUMMARY OF MODELED IMPACTS FROM SO2 CONTROL VISIBILITY IMPACT ANALYSIS FOR SN-02 (2001-2003)

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR

M

a

xim

u

m

Im

p

act (ǻ

d

v)

98% Im

p

act

(ǻ

d

v)

#

D

a

ys >

0.5

ǻ

d

v

M

a

xim

u

m

Im

p

act (ǻ

d

v)

98% Im

p

act

(ǻ

d

v)

#

D

a

ys >

0.5

ǻ

d

v

M

a

xim

u

m

Im

p

act (ǻ

d

v)

98% Im

p

act

(ǻ

d

v)

#

D

a

ys >

0.5

ǻ

d

v

M

a

xim

u

m

Im

p

act (ǻ

d

v)

98% Im

p

act

(ǻ

d

v)

#

D

a

ys >

0.5

ǻ

d

v

Existing Emission

Rate

4.437 1.695 112 2.385 1.185 80 2.263 1.060 65 1.701 0.903 57

Semi-Dry

Scrubber

2.245 0.941 35 0.888 0.418 11 0.803 0.415 6 0.977 0.310 3

Post Control

Improvement†

2.192 0.754 77 1.497 0.767 69 1.460 0.645 59 0.724 0.593 54

Wet Scrubber 2.226 0.920 35 0.899 0.405 10 0.792 0.416 6 0.974 0.315 3

Post Control

Improvement

over Semi-Dry

Scrubber†

0.019 0.021 0 -0.011 0.013 1 0.011 -0.001 0 0.003 -0.005 0

†The visibility improvement shown in the table has been calculated from values that include more decimal places than what is shown in the table. Due to rounding, the visibility

improvement calculated from the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.
Entergy 5-11 Trinity Consultants

BART Analysis – White Bluff

As shown in Table 5-5 and Table 5-6, based on visibility predictions from the CALPUFF modeling

system, the operation of a semi-dry scrubber achieving 0.06 lb/MMBtu will result in up to a 0.813

ǻdv improvement (depending on the Class I area) to the existing 98th percentile day of visibility

impairment attributable to SN-01 and up to 0.767 ǻdv improvement for SN-02. By comparison, wet

scrubbing achieving 0.04 lb/MMBtu only adds up to an additional 0.028 ǻdv improvement for SN-01

and up to 0.021 ǻdv improvement for SN-02.

For convenience, Tables 5-7 and 5-8 provide a condensed summary of the predicted improvements to

visibility impairment alongside the estimated control costs. While the application of wet scrubbing

may be able to achieve a nominally lower outlet SO2 emission rate, there is essentially no incremental

visibility benefit of going from semi-dry scrubbing to wet scrubbing. Further, in some cases,

CALPUFF predicts worse visibility impairment for wet scrubbing as opposed to semi-dry scrubbing.

This is likely due to the higher SO4 emissions associated with wet vs dry scrubbing. Overall, the very

small differences in predicted visibility impacts likely fall within the relative accuracy level of

CALPUFF’s modeling results. Given that wet scrubbing requires a significantly higher capital

investment and is more expensive from an incremental cost effectiveness standpoint than semi-dry

scrubbing, it cannot be justified as BART at SN-01 and SN-02. The adverse non-air environmental

impacts from wet scrubbing also make it a less desirable control technology.
Entergy 5-12 Trinity Consultants

BART Analysis – White Bluff

TABLE 5-7. INCREMENTAL COST EFFECTIVENESS FOR SN-01 WITH CLASS I AREA IMPROVEMENT

Unit ID Control Description

SO2

Emissions

(lb/MMBtu)

Control Eff.

From

Baseline

(%)

Emission

Reduction

from Baseline

(tons/yr)

Installed

Cost

($)

Total Annual

Control Cost

($)

Pollution

Control

Cost

($/ton)

Incremental

Cost

Compared to

Semi-dry

Scrubbing

($/ton) Class I Area

Baseline

98th

Percentile

 ̈dv

 Controlled

98th

Percentile

 ̈dv

Improvement

in 98th

Percentile

 ̈dv

Incremental

Improvement

in 98th

Percentile  ̈dv

Compared to

Semi-dry

Scrubbing

Baseline #

Days > 0.5

 ̈dv

Controlled

# Days >

0.5  ̈dv

Improvement

in Controlled

# Days > 0.5

 ̈dv

Compared to

Semi-dry

Scrubbing

Caney Creek 1.628 0.815 0.813 - 106 27 -

Hercules-Glades 1.041 0.358 0.683 - 61 5 -

Mingo 0.887 0.267 0.620 - 56 2 -

Upper Buffalo 1.140 0.378 0.762 - 77 6 -

Caney Creek 1.628 0.794 0.834 0.021 106 26 1

Hercules-Glades 1.041 0.360 0.681 -0.002 61 3 2

Mingo 0.887 0.271 0.616 -0.004 56 1 1

Upper Buffalo 1.140 0.350 0.790 0.028 77 6 0

0.04 95%

-

26,701

17,892.26 335,133,908

SN-01 Wet Scrubbing 66,885,535 3,626

52,128,084 2,913

18,444.95 389,496,052

SN-01 Semi-dry Scrubbing 0.06 93%

TABLE 5-8. INCREMENTAL COST EFFECTIVENESS FOR SN-02 WITH CLASS I AREA IMPROVEMENT

Unit ID Control Description

SO2

Emissions

(lb/MMBtu)

Control Eff.

From

Baseline

(%)

Emission

Reduction

from Baseline

(tons/yr)

Installed

Cost

($)

Total Annual

Control Cost

($)

Pollution

Control

Cost

($/ton)

Incremental

Cost

Compared to

Semi-dry

Scrubbing

($/ton) Class I Area

Baseline

98th

Percentile

 ̈dv

 Controlled

98th

Percentile

 ̈dv

Improvement

in 98th

Percentile

 ̈dv

Incremental

Improvement

in 98th

Percentile  ̈dv

Compared to

Semi-dry

Scrubbing

Baseline #

Days > 0.5

 ̈dv

Controlled

# Days >

0.5  ̈dv

Incremental

Improvement

in Controlled

# Days > 0.5

 ̈dv

Compared to

Semi-dry

Scrubbing

Caney Creek 1.695 0.941 0.754 - 112 35 -

Hercules-Glades 1.060 0.415 0.645 - 65 6 -

Mingo 0.903 0.310 0.593 - 57 3 -

Upper Buffalo 1.185 0.418 0.767 - 80 11 -

Caney Creek 1.695 0.920 0.775 0.021 112 35 0

Hercules-Glades 1.060 0.416 0.644 -0.001 65 6 0

Mingo 0.903 0.315 0.588 -0.005 57 3 0

Upper Buffalo 1.185 0.405 0.780 0.013 80 10 1

SN-02 Wet Scrubbing

0.06 92%

0.04 95%

SN-02 Semi-dry Scrubbing -

4,158 27,218

15,542.83

66,885,535

335,133,908 52,150,047 3,355

16,084.22 389,496,052
Entergy 5-13 Trinity Consultants

BART Analysis – White Bluff

5.6 PROPOSED BART FOR SO2 FOR SN-01 AND SN-02

Entergy is proposing that the SO2 BART emission level for SN-01 and SN-02 be 0.06 lb/MMBtu

based on the installation and operation of a semi-dry scrubber or whatever technology may become

available to achieve that level of control. EPA has previously agreed that “this [SDA] technology is

BART for these two units.”24 Entergy is proposing to meet this limit on a 30-day rolling average

basis. This emission level provides for a very small compliance margin considering the variability of

the coal content for the White Bluff units; therefore, the proposed 30-day averaging period and

compliance demonstration method is critical. Compliance will be demonstrated using data from the

existing CEMS.

5.6.1 COMPARATIVE SO2 BART DETERMINATIONS

EPA has agreed with similar and even less stringent SO2 BART determinations in other states. For

example, in Oklahoma,25 EPA agreed with the BART determination of 0.06 lb/MMBtu achieved

through use of dry scrubbers for similar boilers, based on the minimal visibility improvement

associated with wet vs dry scrubbing.. In Nebraska26 at GGS, BART for SO2 was also determined to

be 0.06 lb/MMBtu achieved through the use of dry scrubbers. These similar units provide a good

comparison of emission levels achievable through similar control technology.

Other BART determinations have resulted in higher emission limitations. For example, in

Alabama,27 a smaller EGU was allowed an emission limitation of 0.47 lb/MMBtu through use of flue

solvent injection or comparable technologies. In Arizona,28 SO2 BART was determined to be in the

range of 0.08 – 0.15 lb/MMBtu from existing wet scrubbers. An EGU in Colorado29 has a proposed

BART emission rate of 0.13 lb/MMBtu through use of dry scrubbing. A lower emission rate of 0.09

lb/MMBtu was evaluated and determined not reasonable due to the minimal visibility improvement

projected as compared to the higher costs of scrubbing to meet the lower rate.

In other determinations, such as Illinois,30 the control technology was not stated in the BART

determination but the SO2 rate determined to be BART was in the range of 0.11 – 0.23 lb/MMBtu,

dependent upon boiler type and averaging considerations. SO2 BART in Kansas31 was achieved

through “scrubbing” with an emission limitation of 0.10 lb/MMBtu for one boiler and through wet

scrubbing with an emission limitation of 0.15 lb/MMBtu for another. An EGU in Montana32 similar

to Entergy’s SN-01 and SN-02 has a BART emission rate of 0.08 lb/MMBtu.

24 November 25, 2009, letter from Mr. Jeff Robinson, EPA, to Mr. Tom Rheaume, ADEQ.

25 77 Fed. Reg. 16168 (March 22, 2011).

26 77 Fed. Reg. 40150 (July 6, 2012).

27 77 Fed. Reg. 11937 (February 28, 2012).

28 77 Fed. Reg. 42834 (July 20, 2012).

29 77 Fed. Reg. 18052 (March 26, 2012).

30 77 Fed. Reg. 3966 (January 26, 2012).

31 77 Fed. Reg. 52604 (August 23, 2011).

32 77 Fed. Reg. 23988 (April 20, 2012).
Entergy 5-14 Trinity Consultants

BART Analysis – White Bluff

5.7 SO2 BART FOR SN-05

The maximum visibility impairment predicted by the CALPUFF modeling system for SN-05 is only

0.036 ǻdv33. This is an extremely low level of impairment, so low that it is likely falls within the

level of accuracy that can be attributed to CALPUFF. In addition, this modeling assumes that the

auxiliary boiler operates at the maximum daily emission rate 365 days per year. Since the existing

visibility impairment predicted by CALPUFF is extremely low, to the point of practically being

nonexistent, the impairment cannot be considered significant such as to require controls. Said another

way, the impairment is so low that any improvement from reductions would be less than negligible.

Therefore, no controls will be considered BART for SN-05. This conclusion is consistent with EPA’s

determinations for similar boilers in other states, such as the auxiliary boiler at the Basin Electric

Power Cooperative’s Leland Olds Station located in North Dakota or the auxiliary boiler at the

Golden Valley Electric Association’s Healy Power plant in Fairbanks, Alaska.

33 See Table 4-4
Entergy 6-1 Trinity Consultants

BART Analysis – White Bluff

6. NOX BART EVALUATION

6.1 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL

TECHNOLOGIES FOR SN-01 AND SN-02

Nitrogen oxides, NOX, are produced during fuel combustion when nitrogen contained in both the fuel

and the combustion air is exposed to high temperatures. The origin of the nitrogen (i.e. fuel vs.

combustion air) has led to the use of the terms “thermal” NOX and “fuel” NOX when describing NOX

emissions. Thermal NOX emissions are produced when elemental nitrogen in the combustion air is

exposed to a high temperature zone and oxidized. Fuel NOX emissions are created during the rapid

oxidation of nitrogen compounds contained in the fuel.

Nitrogen oxide (NO) is typically the predominant form of NOX from fossil fuel combustion. Nitrogen

dioxide (NO2) makes up the remainder of the NOX. The formation of NOX compounds in utility

boilers is sensitive to the method of firing. In tangentially-fired boilers, such as SN-01 and SN-02, a

single rotating flame is created in the center of the furnace, rather than the discrete flames produced

by burners in the wall-fired boilers. Tangentially fired boilers typically have lower uncontrolled NOX

emissions than wall-fired boilers. Therefore, baseline NOX emission rates can vary significantly from

plant to plant due to method of firing as well as several other factors.

Step 1 of the BART determination is the identification of all available retrofit NOX control

technologies. The available retrofit NOX control technologies are summarized in Table 6-1 for

SN-01 and SN-02.

NOX emissions controls, as listed in Table 6-1, can be categorized as combustion or post-combustion

controls. Combustion controls, including flue gas recirculation (FGR), overfire air (OFA) or

separated OFA (SOFA), and Low NOX Burners (LNB), reduce the peak flame temperature and excess

air in the furnace which minimizes NOX formation. Post-combustion controls, such as selective

catalytic reduction (SCR) and selective non-catalytic reduction (SNCR), convert NOX in the flue gas

to molecular nitrogen and water.

TABLE 6-1. AVAILABLE NOX CONTROL TECHNOLOGIES FOR SN-01 AND SN-02

NOX Control Technologies

Combustion Controls

Flue Gas Recirculation (FGR)

Separated Overfire Air (SOFA)

Low NOX Burners (LNB)

Post-Combustion Controls Selective Catalytic Reduction (SCR)

Selective Non-Catalytic Reduction (SNCR)

6.2 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible NOX control technologies that

were identified in Step 1. Control ranges were developed using a combination of literature control

ranges and efficiencies. Because many controlled emissions rates from literature values were higher
Entergy 6-2 Trinity Consultants

BART Analysis – White Bluff

than the baseline NOX rate at SN-01 and SN-02, vendor estimates were also used to assist in

developing the expected emission rates from the known relationships between the control options.

6.2.1 COMBUSTION CONTROLS

6.2.1.1 FLUE GAS RECIRCULATION (FGR)

FGR uses flue gas as an inert material to reduce flame temperatures. In a

typical flue gas recirculation system, flue gas is collected from the combustion

chamber or stack and returned to the burner via a duct and blower. The

addition of flue gas reduces the oxygen content of the “combustion air” (air +

flue gas) in the burner. The lower oxygen level in the combustion zone reduces

flame temperatures, which in turn reduces thermal NOX formation. However,

vendor-specific review of the White Bluff boilers has concluded that NOX

reduction efficiency data for coal-fired units with FGR are limited. The amount

of NOX reduction achievable with FGR depends primarily on the fuel nitrogen

content and amount of FGR used. Generally, FGR is more effective when used

with low nitrogen content fuels such as natural gas and propane, since FGR is

more effective in controlling thermal NOX rather than fuel NOX. Industry

experience with FGR on coal-fired units for steam temperature control has

shown very high maintenance on the gas recirculation fans due to erosion and

corrosion. Many of the units with FGR for steam temperature control have

removed the recirculation fans from service. The NOX control achievable on

tangentially fired units like White Bluff – Units 1&2 with LNB+OFA has been

comparable to that of FGR at lower capital and O&M cost. Currently, FGR

technology is not offered by OEMs for coal-fired units. For these reasons, FGR

is not a feasible technology for the White Bluff coal-fired units.

6.2.1.2 OVERFIRE AIR (OFA) / SEPARATED OVERFIRE AIR (SOFA)

OFA diverts a portion of the total combustion air from the burners and injects it

through separate air ports above the top level of burners. Staging of the

combustion air creates an initial fuel-rich combustion zone with a lower peak

flame temperature. This reduces the formation of thermal NOX by lowering

combustion temperature and limiting the availability of oxygen in the

combustion zone where NOX is most likely to be formed.

SOFA refers to a system wherein the OFA is injected in a separate wind box

mounted above the main wind box in order to achieve greater separation from

the combustion zone resulting in more effective NOX suppression. SOFA as a

single NOX control technique results in estimated NOX emissions for coal fired

boilers of approximately 10%,34 or 0.28-0.32 lb/MMBtu from SN-01 and SN02. This control is a technically feasible option for the control of NOX from

SN-01 and SN-02.

34 Id.
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6.2.1.3 LOW NOX BURNERS (LNB)

LNB technology utilizes advanced burner design to reduce NOX formation

through the restriction of oxygen, lowering of flame temperature, and/or

reduced residence time. NOX creation rates typically peak at oxygen levels of

five to seven percent.35 LNB is a staged combustion process that is designed to

split fuel combustion into two zones. In the primary zone, NOX formation is

limited by one of two methods. Under staged fuel-rich conditions, low oxygen

levels limit flame temperatures resulting in less NOX formation. The primary

zone is then followed by a secondary zone in which the incomplete combustion

products formed in the primary zone act as reducing agents. Alternatively,

under staged fuel-lean conditions, excess air will reduce flame temperature to

reduce NOX formation. In the secondary zone, combustion products formed in

the primary zone act to lower the local oxygen concentration, resulting in a

decrease in NOX formation.

When combined with SOFA, the estimated NOX emission rate is 0.15

lb/MMBtu.36 LNB systems with SOFA are technically feasible for the control

of NOX from SN-01 and SN-02.

6.2.2 POST COMBUSTION CONTROLS

6.2.2.1 SELECTIVE CATALYTIC REDUCTION (SCR)

SCR refers to the process in which NOX is reduced by ammonia over a

heterogeneous catalyst in the presence of oxygen. The process is termed

selective because the ammonia preferentially reacts with NOX rather than

oxygen, although the oxygen enhances the reaction and is a necessary

component of the process. The overall reactions are:

4NO + 4NH3 + O2 Æ 4N2 + 6H2O

2NO2 + 4NH3 + O2 Æ 3N2 + 6H2O

The SCR process requires a reactor, a catalyst, and an ammonia storage and

injection system. The effectiveness of an SCR system is dependent on a variety

of factors, including the inlet NOX concentration, the exhaust temperature, the

ammonia injection rate, and the type of catalyst. When combined with LNB

and OFA, the estimated NOX emission rate is 0.055 lb/MMBtu.37 This control

is a technically feasible option for the control of NOX from SN-01 and SN-02.

6.2.2.2 SELECTIVE NON-CATALYTIC REDUCTION (SNCR)

In SNCR systems, a reagent is injected into the flue gas in the furnace within an

appropriate temperature window. The NOX and reagent (ammonia or urea)

35 http://www.energysolutionscenter.org/boilerburner/Workshop/RCTCombustion.htm.

36 2012 S&L NOx Study.

37 Id., this rate includes consideration of normal fluctuations which may occur over a 30-day compliance period.
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BART Analysis – White Bluff

react to form nitrogen and water. A typical SNCR system consists of reagent

storage, multi-level reagent-injection equipment, and associated control

instrumentation. The SNCR reagent storage and handling systems are similar

to those for SCR systems. However, both ammonia and urea SNCR processes

require three to four times as much reagent as SCR systems to achieve similar

NOX reductions. When combined with LNB/OFA, the estimated NOX emission

rate is 0.13 lb/MMBtu.38 This control is a technically feasible option for the

control of NOX from SN-01 and SN-02.

38 Id.
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BART Analysis – White Bluff

6.3 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY

EFFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to

effectiveness. Table 6-2 provides a ranking of the control levels for the controls listed in the

previous section.

TABLE 6-2. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NOX CONTROL

TECHNOLOGIES

Control Technology

Estimated Controlled

Level for SN-01 and

SN-02

(lb/MMBtu)

SOFA 0.28-0.32

LNB/SOFA 0.15

LNB/SOFA + SNCR 0.13

LNB/SOFA + SCR 0.055

Current NOX emissions are approximately 0.31 lb/MMBtu from SN-01 and approximately 0.36

lb/MMBtu from SN-02. Based on evaluations by S&L, it is believed that combustion controls such

as LNB in combination with SOFA will achieve a NOX level of 0.15 lb/MMBtu for SN-01 and SN02.39 Further, it is believed that the addition of SCR to LNB/SOFA will achieve a NOX level of

approximately 0.055 lb/MMBtu at each unit and LNB/SOFA + SNCR will achieve a level of 0.13

lb/MMBtu at each unit.

6.4 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS

Step four for the BART analysis is the impact analysis. The BART determination guidelines list four

factors to be considered in the impact analysis:

Ÿ Cost of compliance;

Ÿ Energy impacts;

Ÿ Non-air quality impacts; and

Ÿ The remaining useful life of the source.

6.4.1 COST OF COMPLIANCE

The capital costs, operating costs, and cost effectiveness of LNB/SOFA, LNB/SOFA +

SNCR and LNB/SOFA + SCR were estimated for the cost analysis.

39 EPA established presumptive SO2 and NOX controls for coal-fired EGUs in the BART rule. For dry bottom

tangentially-fired EGUs, the presumptive NOX limit is 0.15 lb/MMBtu. (Regional Haze Regulations and Guidelines for

Best Available Retrofit Technology (BART Determinations; Final Rule.”) 77 FR 39134 (July 6, 2005).
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BART Analysis – White Bluff

Control Costs

Control costs were calculated using vendor capital and operating cost estimates specific to

the units. The capital costs were annualized over a 30-year period and then added to the

annual operating costs to obtain the total annualized costs.

The details of the capital and operating cost estimates are provided in Appendix A of this

report.

It should be noted that the capital costs presented for the various NOx control options do

not include any Allowance for Funds Used During Construction (AFUDC). AFUDC

represents the interest expense incurred on the investment in a large capital project, such as

a NOx controls installation, during the construction phase, which can take many months to

several years to complete. While interest expenses will certainly be incurred on a such a

project, and AFUDC is typically considered as part of the capital cost of such a project for

standard accounting and rate-making purposes, EPA Region 6 has expressed concern with

the inclusion of this expense. In order to facilitate review of this revised FFA, Entergy,

without waiver, has omitted this cost from the capital costs presented within this FFA.

Annual Tons Reduced

The annual tons reduced that were used in the cost effectiveness calculations were

determined by subtracting the estimated controlled annual emission rate from the baseline

annual emission rate.

The baseline annual emission rates were the average rates from 2009-2011, as reported by

Entergy in their air emission inventories. The controlled annual emission rate is based on

the lb/MMBtu level believed to be achievable from the control technology multiplied by

the future annual input to the boiler in MMBtu/yr. The future annual heat input is based on

the average hourly heat input from CAMD for 2001 to 2003 multiplied by the average

annual operating hours from 2001to 2003 for each boiler. This was the same approach that

was used to estimate future annual heat input in the review of SO2 controls

Cost Effectiveness

The cost effectiveness in dollars per ton of NOX reduced was determined by dividing the

annualized cost of control by the annual tons reduced. An incremental cost analysis was

also performed to show the incremental increase in costs between LNB/SOFA + SCR and

an LNB/SOFA system, as well as between LNB/SOFA + SNCR and LNB/SOFA. The

costs effectiveness analysis is summarized in Table 6-3.

In the BART guidelines, EPA calculated that for all types of boilers other than cyclone

boilers, combustion control technology is generally more cost-effective than postcombustion controls. EPA estimates that approximately 75 percent of the BART units

(non-cyclone) could meet the presumptive NOX limits at a cost of $100 to $1,000 per ton of
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BART Analysis – White Bluff

NOX removed based on the use of combustion control technology.40 For the units that

could not meet the presumptive limits using combustion control technology, EPA estimates

that almost all of these sources could meet the presumptive limits using advanced

combustion controls. The EPA estimates that the costs of such controls are usually less

than $1,500 per ton of NOX removed.41

Table 6-3 indicates that the cost effectiveness of LNB/SOFA is approximately $375 per ton

of NOX removed. Installing LNB/SOFA would reduce NOX emissions by more than 50%.

By contrast, the incremental cost effectiveness of adding SNCR to LNB/SOFA is

approximately $10,000/ton per unit. Similarly, the incremental cost of adding SCR to

LNB/SOFA is approximately $7,250-$8,000/ton per unit.

Table 6-3 also demonstrates the improvement in the maximum of the 98th percentile

visibility impairment results due to each control technology. As Table 6-3 clearly shows,

LNB/SOFA + SNCR offers very little visibility improvement over LNB/SOFA alone

(~0.03 dv). The addition of SCR incrementally improves visibility over LNB/SOFA by

only approximately 0.1 dv at an annual cost of well over $20,000,000 per unit. Such a

large cost cannot be justified by the negligible visibility improvement provided by SCR.

40 Id. at 39134-39135.

41 Id.
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BART Analysis – White Bluff

TABLE 6-3. SUMMARY OF COST EFFECTIVENESS FOR SN-01 AND SN-02 NOX CONTROLS

Baseline

Emission

Rate

Controlled

Emission Level

Annual Heat

Input1

Controlled

Emission

Rate

NOx

Reduced Capital Cost

Annual

Capital Cost

Annual Fixed

O&M

Annualized

Variable O&M

Total Annual

Cost

Cost

Effectiveness

 Incremental

Cost Compared

to LNB/SOFA

Incremental

Visbility

Improvement2

(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton) (dv)

SN-01 LNB/SOFA 7,249.23 0.15 55,269,197 4145.19 3104.04 10,461,206 843,031 142,000 177,887 1,162,918 375 - 0.176

SN-01 LNB/SOFA/SNCR 7,249.23 0.13 55,269,197 3592.50 3656.73 21,371,325 1,722,238 311,000 4,538,000 6,571,238 1,797 9,785 0.024

SN-01 LNB/SOFA/SCR 7,249.23 0.055 55,269,197 1519.90 5729.33 230,329,138 18,561,397 608,000 2,836,000 22,005,397 3,841 7,939 0.093

(tpy) (lb/MMBtu) (MMBtu/yr) (tpy) (ton/yr) ($) ($/yr) ($/yr) ($/yr) ($/yr) ($/ton) ($/ton) (dv)

SN-02 LNB/SOFA 8,185.33 0.15 54,138,841 4060.41 4124.91 14,488,206 1,167,552 142,000 170,838 1,480,391 359 - 0.225

SN-02 LNB/SOFA/SNCR 8,185.33 0.13 54,138,841 3519.02 4666.30 25,398,325 2,046,760 311,000 4,542,000 6,899,760 1,479 10,010 0.033

SN-02 LNB/SOFA/SCR 8,185.33 0.055 54,138,841 1488.82 6696.51 206,747,898 16,661,070 608,000 2,858,000 20,127,070 3,006 7,251 0.102

2. The incremental visibility improvement for LNB/SOFA is the maximum visibility improvement in the 98th percentile impact compared to baseline (See Tables 6-5 and 6-6). The incremental visibility improvement for LNB/SOFA/SNCR and LNB/SOFA/SCR

is the difference between the maximum improvement due to LNB/SOFA/SNCR or LNB/SOFA/SCR in the four Class I areas considered in the analysis less the maximum visibility improvement in the four Class I areas from LNB/SOFA (See Tables 6-5 and 6-6).

1. The future annual heat input was estimated by multiplying the average hourly heat input from CAMD for 2009-2011 for each boiler by the average number of operating hours for each boiler from 2009-2011.
Entergy 6-9 Trinity Consultants

BART Analysis – White Bluff

6.4.2 ENERGY IMPACTS & NON-AIR IMPACTS

As noted in Table 6-3 and in Section 6.5 below, SCR and SNCR systems are capable of

achieving additional NOX mass emission reductions in comparison to combustion controls

such as LNB/SOFA. However, both SCR and SNCR systems create additional energy

and/or non-air environmental impacts. SCR and SNCR systems require electricity to

operate the ancillary equipment. The need for electricity to help power some of the

ancillary equipment creates a demand for energy that currently does not exist.

SCR and SNCR can potentially cause significant environmental impacts. The primary

avenue is related to the storage of ammonia. The storage of aqueous ammonia above

10,000 lbs is regulated by a risk management program (RMP), since the accidental release

of ammonia has the potential to cause serious injury and death to persons in the vicinity of

the release. Additionally, SCR and SNCR will likely also cause the release of unreacted

ammonia to the atmosphere. This is referred to as ammonia slip. Ammonia slip from

SCR and SNCR systems occurs either from ammonia injection at temperatures too low for

effective reaction with NOX, leading to an excess of unreacted ammonia, or from overinjection of reagent leading to uneven distribution; which also leads to an excess of

unreacted ammonia. Ammonia released from SCR and SNCR systems will react with

sulfates and nitrates in the atmosphere to form ammonium sulfate and ammonium nitrate.

Together, ammonium sulfate and ammonium nitrate are the predominant sources of

regional haze.

Another environmental impact associated with SCR is the disposal of catalyst waste. To

maintain NOX-removal effectiveness, the catalyst in an SCR system must periodically be

cleaned, regenerated, or replaced. Cleaning and regeneration are preferred, but eventually

the catalyst reaches the end of its useful life and must be replaced. Ideally the exhausted

catalyst can be recycled for reuse, however, if the condition of the spent catalyst does not

warrant recycling or a market is unavailable, the old catalyst must be disposed of. Current

regulatory interpretations indicate spent SCR catalysts are exempted from hazardous waste

regulation via 40 CFR § 261.4(b)(4) (Bevill Exemption) as flue gas emission control

wastes. However, ongoing efforts by EPA to increase regulatory oversight of coal

combustion residuals could alter that exemption, and create the potential that spent SCR

catalysts would be characterized as hazardous wastes, hence increasing the cost of disposal.

Regardless of the regulatory treatment of the waste, the disposal creates additional

potential financial and environmental impacts associated with an SCR system.

6.4.3 REMAINING USEFUL LIFE

The remaining useful life of SN-01 and SN-02 are sufficiently long such that it does not

affect the BART analysis.
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6.5 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS

A final impact analysis was conducted to assess the visibility improvement for existing emission rates

when compared to the emission rates associated with LNB/SOFA, LNB/SOFA + SNCR and

LNB/SOFA + SCR. Section 4 of this report documented the existing visibility impairment

attributable to SN-01 and SN-02. In order to assess the visibility improvement associated with

LNB/SOFA, SCR and SNCR systems, the NOX emission rates associated with the control systems

were modeled using CALPUFF. The controlled emission level associated with LNB/SOFA system is

0.15 lb/MMBtu; the controlled emission level associated with SOFA + SNCR is 0.13 lb/MMBtu; and

the controlled emission level associated with LNB/SOFA + SCR systems is 0.055 lb/MMBtu for each

unit. These levels were multiplied by the maximum heat input to derive the hourly emission rates

used in the modeling.

Table 6-4 summarizes the NOX emission rates that were modeled to reflect the LNB/SOFA,

LNB/SOFA + SNCR, and LNB/SOFA + SCR. The emission rates for the other pollutants shown in

Tables 6-4 are the same as in the baseline modeling.
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TABLE 6-4. SUMMARY OF EMISSION RATES MODELED TO REFLECT NOX CONTROLS

SO2

(lb/hr)

SO4

(lb/hr)

NOX

(lb/hr)

PMC

(lb/hr)

PMF

(lb/hr)

SOA

(lb/hr)

EC

(lb/hr)

PM10, total

(lb/hr)

SN-01 –

LNB/SOFA 7,763.5 36.8 1342.5 40.4 31.1 9.2 1.2 118.6

SN-02 –

LNB/SOFA 7,825.1 36.8 1342.5 40.4 31.1 9.2 1.2 118.6

SN-01 -

LNB/SOFA +

SNCR 7,763.5 36.8 1163.5 40.4 31.1 9.2 1.2 118.6

SN-02 -

LNB/SOFA +

SNCR 7,825.1 36.8 1163.5 40.4 31.1 9.2 1.2 118.6

SN-01 –

LNB/SOFA +

SCR 7,763.5 36.8 492.3 40.4 31.1 9.2 1.2 118.6

SN-02 -

LNB/SOFA +

SCR 7,825.1 36.8 492.3 40.4 31.1 9.2 1.2 118.6

Tables 6-5 and 6-6 provide a comparison of the existing visibility impairment and the visibility

impairment associated with the addition of NOX controls on SN-01 and SN-02, respectively, in all

affected Class I areas, including the maximum modeled visibility impact, the 98th percentile modeled

visibility impact, and the number of days with a modeled visibility impact greater than 0.5 ǻdv.
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TABLE 6-5. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEMS ON SN-01 (2001-2003)

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR

Maxim

u

m Im

pact (ǻ

dv)

98% Im

pact (ǻ

dv)

# Days > 0.5 ǻ

dv

Maxim

u

m Im

pact (ǻ

dv)

98% Im

pact (ǻ

dv)

# Days > 0.5 ǻ

dv

Maxim

u

m Im

pact (ǻ

dv)

98% Im

pact (ǻ

dv)

# Days > 0.5 ǻ

dv

Maxim

u

m Im

pact (ǻ

dv)

98% Im

pact (ǻ

dv)

# Days > 0.5 ǻ

dv

Existing Emission Rate 4.194 1.628 106 2.339 1.140 77 2.230 1.041 61 1.569 0.887 56

LNB/OFA 3.465 1.462 89 2.243 1.039 62 2.175 0.865 48 1.168 0.849 45

Post Control

Improvement

0.729 0.166 17 0.096 0.101 15 0.055 0.176 13 0.401 0.038 11

LNB/OFA + SNCR 3.386 1.428 86 2.233 1.029 62 2.170 0.844 47 1.146 0.842 44

Incremental

Improvement Over

LNB/SOFA

0.079 0.034 3 0.010 0.01 0 0.005 0.021 1 0.022 0.007 1

LNB/OFA + SCR 3.089 1.359 73 2.196 0.991 59 2.148 0.832 45 1.132 0.817 38

Incremental

Improvement Over

LNB/OFA

0.376 0.103 16 0.047 0.048 3 0.027 0.033 3 0.036 0.032 7

†The visibility improvement shown in the table has been calculated from values that include more decimal places than what is shown in the table. Due to rounding, the

visibility improvement calculated from the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement

reflected in the table.
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TABLE 6-6. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEMS ON SN-02 (2001-2003)

\ Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR

Maxim

u

m Im

pact (ǻ

dv)

98% Im

pact (ǻ

dv)

# Days > 0.5 ǻ

dv

Maxim

u

m Im

pact (ǻ

dv)

98% Im

pact (ǻ

dv)

# Days > 0.5 ǻ

dv

Maxim

u

m Im

pact (ǻ

dv)

98% Im

pact (ǻ

dv)

# Days > 0.5 ǻ

dv

Maxim

u

m Im

pact (ǻ

dv)

98% Im

pact (ǻ

dv)

# Days > 0.5 ǻ

dv

Existing Emission Rate 4.437 1.695 112 2.385 1.185 80 2.263 1.060 65 1.701 0.903 57

LNB/SOFA 3.483 1.47 91 2.258 1.046 62 2.191 0.870 48 1.174 0.856 45

Post Control

Improvement

0.954 0.225 21 0.127 0.139 18 0.072 0.190 17 0.527 0.047 12

LNB/SOFA + SNCR 3.404 1.437 87 2.248 1.035 62 2.185 0.849 47 1.152 0.849 45

Incremental

Improvement Over

LNB/SOFA

0.079 0.033 4 0.010 0.011 0 0.006 0.021 1 0.022 0.007 0

LNB/SOFA + SCR 3.107 1.368 75 2.211 0.997 59 2.164 0.838 45 1.138 0.823 39

Incremental

Improvement Over

LNB/SOFA

0.376 0.102 16 0.047 0.049 3 0.027 0.032 3 0.036 0.033 6

†The visibility improvement shown in the table has been calculated from values that include more decimal places than what is shown in the table. Due to rounding, the

visibility improvement calculated from the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement

reflected in the table.
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In light of the very small incremental visibility benefit and the high marginal cost, SNCR cannot be

considered BART for either SN-01 or SN-02. As shown in Table 6-5 and Table 6-6, based on

visibility predictions from the CALPUFF modeling system, the operation of a LNB/SOFA will result

in up to a 0.176 ǻdv improvement (depending on the Class I area) to the existing visibility

impairment attributable to SN-01 and up to 0.225 ǻdv improvement for SN-02. There is essentially

zero visibility improvement due to including SNCR, with a modeled change of approximately 0.03

ǻdv for both units. The addition of SCR would produce a modeled improvement of only 0.103 ǻdv

for Unit 1 and 0.102 ǻdv for Unit 2 over LNB/SOFA alone.

Tables 6-7 and 6-8 provide a condensed summary of these predicted improvements alongside the

estimated control costs. The incremental benefit of going from LNB/SOFA to either LNB/SOFA +

SCNR or LNB/SOFA + SCR is clearly not justified. The control technologies are very expensive in

terms of initial capital investment and are prohibitively more expensive from an incremental cost

effectiveness standpoint than LNB/SOFA alone.
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TABLE 6-7. INCREMENTAL COST EFFECTIVENESS FOR SN-01 WITH CLASS I AREA IMPROVEMENT

Unit ID Control Description

NOx

Emissions

(lb/MMBtu)

Control Eff.

From

Baseline

(%)

Emission

Reduction

from Baseline

(tons/yr)

Installed

Cost

($)

Total Annual

Control Cost

($)

Pollution

Control

Cost

($/ton)

Incremental

Cost

Compared to

LNB/SOFA

($/ton) Class I Area

Baseline

98th

Percentile

 ̈dv

 Controlled

98th

Percentile

 ̈dv

Improvement

in 98th

Percentile

 ̈dv

Incremental

Improvement

in 98th

Percentile  ̈dv

Compared to

LNB/SOFA

Baseline #

Days > 0.5

 ̈dv

Controlled

# Days >

0.5  ̈dv

Incremental

Improvement

in Controlled

# Days > 0.5

 ̈dv

Compared to

LNB/SOFA

Caney Creek 1.628 1.462 0.166 - 106 89 -

Hercules-Glades 1.041 0.865 0.176 - 61 48 -

Mingo 0.887 0.849 0.038 - 56 45 -

Upper Buffalo 1.140 1.039 0.101 - 77 62 -

Caney Creek 1.628 1.428 0.200 0.034 106 86 3

Hercules-Glades 1.041 0.844 0.197 0.021 61 47 1

Mingo 0.887 0.842 0.045 0.007 56 44 1

Upper Buffalo 1.140 1.029 0.111 0.010 77 62 0

Caney Creek 1.628 1.359 0.269 0.103 106 73 16

Hercules-Glades 1.041 0.832 0.209 0.033 61 45 3

Mingo 0.887 0.817 0.070 0.032 56 38 7

Upper Buffalo 1.140 0.991 0.149 0.048 77 59 3

SN-01 LNB/SOFA

SN-01 LNB/SOFA + SCR

SN-01 LNB/SOFA + SNCR 3,656.73

0.055 82% 5,729.33

10,461,206

21,371,325

0.15 51%

0.13 58%

3,104.04 1,162,918

230,329,138 3,841 7,939

-

6,571,238 1,797 9,785

375

22,005,397

TABLE 6-8. INCREMENTAL COST EFFECTIVENESS FOR SN-02 WITH CLASS I AREA IMPROVEMENT

Unit ID Control Description

NOx

Emissions

(lb/MMBtu)

Control Eff.

From

Baseline

(%)

Emission

Reduction

from Baseline

(tons/yr)

Installed

Cost

($)

Total Annual

Control Cost

($)

Pollution

Control

Cost

($/ton)

Incremental

Cost

Compared to

LNB/SOFA

($/ton) Class I Area

Baseline

98th

Percentile

 ̈dv

 Controlled

98th

Percentile

 ̈dv

Improvement

in 98th

Percentile

 ̈dv

Incremental

Improvement

in 98th

Percentile  ̈dv

Compared to

LNB/SOFA

Baseline #

Days > 0.5

 ̈dv

Controlled

# Days >

0.5  ̈dv

Incremental

Improvement

in Controlled

# Days > 0.5

 ̈dv

Compared to

LNB/SOFA

Caney Creek 1.695 1.470 0.225 - 112 91 -

Hercules-Glades 1.060 0.870 0.190 - 65 48 -

Mingo 0.903 0.856 0.047 - 57 45 -

Upper Buffalo 1.185 1.046 0.139 - 80 62 -

Caney Creek 1.695 1.437 0.258 0.033 112 87 4

Hercules-Glades 1.060 0.849 0.211 0.021 65 47 1

Mingo 0.903 0.849 0.054 0.007 57 45 0

Upper Buffalo 1.185 1.035 0.150 0.011 80 62 0

Caney Creek 1.695 1.368 0.327 0.102 112 75 16

Hercules-Glades 1.060 0.838 0.222 0.032 65 45 3

Mingo 0.903 0.823 0.080 0.033 57 39 6

Upper Buffalo 1.185 0.997 0.188 0.049 80 59 3

SN-02 LNB/SOFA + SCR 6,696.51

SN-02 LNB/SOFA + SNCR

7,251

1,479 10,010

0.055 85% 20,127,070 3,006

6,899,760

206,747,898

206,747,898

SN-02 LNB/SOFA 0.15

0.13 4,666.30

58% 4,124.91

63%

14,488,206 1,480,391 359 -
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6.6 PROPOSED BART FOR NOX FOR SN-01 AND SN-02

If CSAPR ultimately is upheld and implemented in Arkansas, Entergy may rely on CSAPR to satisfy

its NOX regional haze obligations at SN-01 and SN-02. Alternatively, if CSAPR is vacated and CAIR

remains in place, Entergy may rely on CAIR to satisfy its NOX obligations under BART as EPA has

previously determined that the CAIR season NOX trading program provides greater visibility

improvement than BART.

With full consideration of all five factors outlined by EPA for BART determinations, Entergy

proposes a BART emission level of 0.15 lb/MMBtu on a 30-day rolling average basis, achievable

through use of LNB/SOFA at SN-01 and SN-02. Compliance will be demonstrated using data from

the existing CEMS. This determination is consistent with the BART determinations approved by

EPA in Oklahoma, including the determinations for OG&E Seminole Units 1, 2, and 3 that

combustion controls achieving 30-day rolling average NOX levels of 0.203 lb/MMBtu, 0.212

lb/MMBtu, and 0.164 lb/MMBtu, respectively, constitute BART and the determination for OG&E

Sooner Units 1 and 2, OG&E Muskogee Unit 4, and AEP/PSO Northeastern Units 3 and 4 that

combustion controls achieving a 30-day rolling average NOX level of 0.15 lb/MMBtu constitute

BART.42

6.7 PROPOSED BART FOR NOX FOR SN-05

The maximum visibility impairment predicted by the CALPUFF modeling system for SN-05 is only

0.036 ǻdv43. This is an extremely low level of impairment, so low that it is likely falls within the

level of accuracy that can be attributed to CALPUFF. In addition, this modeling assumes that the

auxiliary boiler operates at the maximum daily emission rate 365 days per year. Since the existing

visibility impairment predicted by CALPUFF is extremely low, to the point of practically being

nonexistent, the impairment cannot be considered significant such as to require controls. Said another

way, the impairment is so low that any improvement from reductions would be less than negligible.

Therefore, no controls is the NOX BART determination for SN-05. This conclusion is consistent with

EPA’s determinations in other states with similar auxiliary boilers.

42 77 Fed. Reg. 16168 (March 22, 2011).

43 See Table 4-4
Entergy 7-1 Trinity Consultants

BART Analysis – White Bluff

7. PM10 BART EVALUATION

EPA’s Approval and Promulgation of Implementation Plans, published March 12, 2012, determined

that the currently installed ESP is BART for PM10 for SN-01 and SN-02.

The federally enforceable operating air permit states the PM emissions from the two units are

controlled with ESPs and requires that the two units comply with a PM emission standard of

0.10 lb/MMBtu. Since we have found that the visibility impact of the source due to PM

emissions alone is so minimal such that the installation of any additional PM controls on the

units would likely achieve very low emissions reductions, have minimal visibility benefits,

and not be cost-effective, we are proposing to approve ADEQ’s determination that PM

BART for both the bituminous and subbituminous coal firing scenarios is the existing PM

emission limit for Units 1 and 2.44

As such, no further PM10 analysis has been conducted.

Section 4 of this report summarized the baseline visibility impairment attributable to SN-01, SN-02

and SN-05. Table 4-4 demonstrates that SN-05 does not contribute to a single day of visibility

impairment greater than 0.5 ǻdv. Therefore, no controls will be considered BART for SN-05. This

conclusion is consistent with EPA’s determinations in other states with similar auxiliary boilers.

44 “Approval and Promulgation of Implementation Plans; Arkansas; Regional Haze State Implementation Plan;

Interstate Transport State Implementation Plan To Address Pollution Affecting Visibility and Regional Haze. Final Rule,”

77 FR 14658 (March 12, 2012).
Entergy Trinity Consultants

BART Analysis – White Bluff

APPENDIX A

SO2 AND NOX CONTROL COST CALCULATIONS
Entergy Trinity Consultants

BART Analysis – White Bluff

Semi-Dry Scrubber Capital and O&M Cost Estimate

Operational Data Unit 1 Unit 2

Maximum HI (MMBtu/hr) 8950 8950

Annual Operating Hours, 2009-2011 7361 7401

Capital Costs1

Unit 1 Unit 2

Total Contractor Costs (2012 Dollars) $174,854,437 $174,854,437

Total Contractor Costs (2010 Dollars): $156,974,274 $156,974,274

 FGD Equipment (2010 Dollars) $57,649,982 $57,649,982

 FGD Materials (2010 Dollars) $14,840,928 $14,840,928

 FGD Contractor Labor (2010 Dollars) $63,607,654 $63,607,654

 FGD Contractor Contingency (2010 Dollars) $20,875,711 $20,875,711

Total Balance of Plant (BOP) Direct Costs (2012 Dollars) $118,537,729 $118,537,729

 Balance of Plant (BOP) Equipment (2012 Dollars) $24,816,321 $24,816,321

 BOP Materials (2012 Dollars) $26,464,135 $26,464,135

 BOP Labor (2012 Dollars) $67,257,273 $67,257,273

Balance of Plant (BOP) Indirect Costs (2012 Dollars) $8,733,104 $8,733,104

Misc Contractor Labor (2012 Dollars) $4,583,719 $4,583,719

Misc Contractor Labor (2010 Dollars)2

$4,115,000 $4,115,000

Entergy Internal Costs (2012 Dollars) $20,076,644 $20,076,644

Entergy Internal Costs (2010 Dollars)3

$18,023,659 $18,023,659

Capital suspense (2010 Dollars) $7,494,603 $7,494,603

Capital suspense (2012 Dollars) $8,348,276 $8,348,276

CEPCI 2008 530.7 530.7

CEPCI 2010 533 533

CEPCI 2012 (January) 593.6 593.6

Total Capital Investment $335,133,908 $335,133,908

Capital Recovery Factor (CRF)4

0.08 0.08

Annual Costs5

CEPCI 2008 530.7 530.7

Direct Annual Costs (2012 Dollars) $8,837,861 $8,859,823

Direct Annual Costs (2008 Dollars) $7,901,369 $7,921,004

 Operating Labor and Materials (2008 Dollars) $4,287,845 $4,287,845

 Water, Waste & Bag Replacement Costs $/MWh (2008 Dollars) 0.29 0.29

 Lime Costs $/MWh (2008 Dollars) 0.75 0.75

 Water, Waste, Bag Replacement and Lime Costs $/MWh (2008 Dollars) 1.04 1.04

 Anticipated Yearly MWh6

3,474,543 3,493,423

 Water, Waste, Bag Replacement and Lime Costs (2008 Dollars) 3,613,525 3,633,160

Indirect Annual Costs (IC) (2012 Dollars): $43,290,224 $43,290,224

 Overhead (2008 Dollars)

60% of total labor and

materials costs $2,572,707 $2,572,707

 Overhead (2012 Dollars) $2,877,631 $2,877,631

 Administrative charges (2012 Dollars) 2% of TCI $6,702,678 $6,702,678

 Property Tax (2012 Dollars) 1% of TCI $3,351,339 $3,351,339

 Insurance (2012 Dollars) 1% of TCI $3,351,339 $3,351,339

 Capital recovery (2012 Dollars) CRF* TCI $27,007,236 $27,007,236

Total Annual Costs $52,128,084 $52,150,047

2: Misc contract labor includes permitting and regulatory support.

3: Entergy internal costs include labor, travel, and loader costs.

 Equipment CRF, 30-yr life, 7% interest

6: Anticipated yearly MWh = (944 MW/2 * anticipated annual operating hours) - 13 MWh, where 944 MW is anticipated EIA share for both boilers and 13 MWh is the

estimated parsitic load loss estimate due to operation of the control from both boilers.

1: The capital costs are based on contractor estimates provided by Sargent & Lundy (S&L) to Entergy in 2010 and other estimates compiled by Entergy in 2008. Both

the 2010 cost from S&L and the 2008 cost estimated by Entergy were scaled to reflect 2012 dollars.

4: CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment life

5: The O&M cost estimates are based on the Sargent & Lundy economic model from May 2008. The cost estimates were scaled to reflect 2012 dollars.
Entergy Trinity Consultants

BART Analysis – White Bluff

Wet Scrubber Capital and O&M Cost Estimate 1

Operational Data Unit 1 Unit 2

Maximum HI (MMBtu/hr) 8950 8950

Annual Operating Hours, 2001-2003 7361 7401

Capital Costs Unit 1 Unit 2

Total Equipment Costs (EC) (2012 Dollars)2$150,037,000 $150,037,000

Purchased Equipment Cost (PEC) PEC = 1.18 * EC $177,043,660 $177,043,660

Total Capital Investment (TCI) $389,496,052 $389,496,052

Capital Recovery Factor (CRF)(2012 Dollars)30.08 0.08

Annual Costs

Direct Annual Costs (DC)4 (2011 Dollars) $15,734,500 $15,734,500

CECPI 2011 585.7 585.7

CECPI 2012 (January) 593.6 593.6

Direct Annual Costs (DC) (2012 Dollars) $15,946,729 $15,946,729

Indirect Annual Costs (IC) (2012 Dollars) $50,938,806 $50,938,806

 Overhead (2011 Dollars)

60% of fixed labor and

material costs from 2011

S&L conceptual costs $2,987,400 $2,987,400

 Overhead (2012 Dollars) $3,027,694 $3,027,694

 Administrative charges (2012 Dollars) 2% of TCI $8,733,104 $8,733,104

 Property Tax (2012 Dollars) 1% of TCI $3,894,961 $3,894,961

 Insurance (2012 Dollars) 1% of TCI $3,894,961 $3,894,961

 Capital recovery CRF* TCI $31,388,086 $31,388,086

Total Annual Costs $66,885,535 $66,885,535

 Equipment CRF, 30-yr life, 7% interest

1: The costing method is modeled after the cost method summarized in Section 5.2 of the EPA Control Cost Manual (Post-Combustion Controls, Chapter 1 - Wet

Scrubbers for Acid Gas, Table 1.3). Costs for capital suspense have been accounted for and added to the TCI calculated using the Cost Control Manual.

4: The direct costs include the fixed O&M from the S&L 2011 conceptual costs (operating labor, operating materials, and maintenance materials) plus variable O&M

from the S&L 2011 conceptual costs (aux power, bags, cages, lime, limestone, and water)

2: The total equipment cost is the sum of the equipment and material costs from the November 30, 2012 Sargent & Lundy conceptual cost estimate.

3: CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment life
Entergy Trinity Consultants

BART Analysis – White Bluff

LNB-SOFA Capital and O&M Cost Estimate

Operational Data Unit 1 Unit 2

Maximum HI (MMBtu/hr) 8950 8950

Annual Operating Hours, 2001-2003 7361 7401

Capital Costs Unit 1 Unit 2

Installed Capital Cost1

10,461,206 14,488,206

Capital Recovery Factor (CRF)2

0.08 0.08

Annual Costs Unit 1 Unit 2

Fixed O&M Costs3

142,000 142,000

Variable O&M Costs4

177,887 170,838

Annualized Capital Cost 843,031 1,167,552

Total Annual Costs 1,162,918 1,480,391

4: The variable O&M costs are based on the Eastern Research Group report "Analysis of Combustion Controls for Reducing

NOx Emissions from Coal-fired EGUs in the WRAP Region" September 6, 2005. Section 4.3.1 and Appendix D.

Variable O&M = (0.027 mills/kW-hr/1000) x (1 kW-hr/10,000 Btu) x H x C x 10^6 Btu/mmBtu

Where:

H = Annual operating hours

C = Boiler design capacity (mmBtu/hr)

Note: The variable rate used for variable O&M costs was 0.027 mills/kW-hr. This is the rate listed in Appendix D

1: The installed capital cost estimates for LNB/OFA are based on the installed capital cost estimates for each unit as provided

by Sargent & Lundy in the 5/16/2013 NOx Control Technology Cost and Performance Study (Unit 1 = $7,804,000 and Unit 2

= $11,831,000) plus additional cost not accounted for in the S&L cost estimate, including cost for permitting and

legal/regulatory support (estimated by Entergy to be $112,500 for each unit), cost for Entergy employee labor and loaders

(estimated by Entergy to be $1,589,033 for each unit), and cost for capital suspense (estimated by Entergy to be $955,673 for

each unit) .

2: CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment life

 Equipment CRF, 30-yr actual service life, 7% interest

3: The fixed O&M cost estimates were provided by Sargent & Lundy in the 5/16/2013 NOx Control Technology Cost and

Performance Study
Entergy Trinity Consultants

BART Analysis – White Bluff

LNB-SOFA + SNCR Capital and O&M Cost Estimate

Operational Data Unit 1 Unit 2

Maximum HI (MMBtu/hr) 8950 8950

Annual Operating Hours, 2001-2003 7361 7401

Capital Costs Unit 1 Unit 2

Installed Capital Cost 1

21,371,325 25,398,325

Capital Recovery Factor (CRF)2

0.08 0.08

Annual Costs Unit 1 Unit 2

Fixed O&M Costs3

311,000 311,000

Variable O&M Costs4

4,538,000 4,542,000

Annualized Capital Cost 1,722,238 2,046,760

Total Annual Costs 6,571,238 6,899,760

4: The variable O&M cost estimates are based on the cost estimates provided by Sargent & Lundy in the 5/16/2013 NOx Control

Technology Cost and Performance Study. Adding LNB/OFA to SNCR makes the variable O&M costs less than that of SNCR alone

due to a lower NOx concentration and resulting less reagent usage.

1: The installed capital cost estimates for LNB/OFA + SNCR are based on the installed capital cost estimates for each unit as

provided by Sargent & Lundy in the 5/16/2013 NOx Control Technology Cost and Performance Study (Unit 1 = $16,290,000 and

Unit 2 = $20,317,000) plus additional cost not accounted for in the S&L cost estimate, including cost for permitting and

legal/regulatory support (estimated by Entergy to be $112,500 for each unit), cost for Entergy employee labor and loaders (estimated

by Entergy to be $3,223,396 for each unit), and cost for capital suspense (estimated by Entergy to be $1,745,429 for each unit) .

2: CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment life

 Equipment CRF, 30-yr actual service life, 7% interest

3: The fixed O&M cost estimates are based on the cost estimates provided by Sargent & Lundy in the 5/16/2013 NOx Control

Technology Cost and Performance Study.
Entergy Trinity Consultants

BART Analysis – White Bluff

LNB-SOFA + SCR Capital and O&M Cost Estimate

Operational Data Unit 1 Unit 2

Maximum HI (MMBtu/hr) 8950 8950

Annual Operating Hours, 2001-2003 7361 7401

Capital Costs1 Unit 1 Unit 2

Installed Capital Cost 230,329,138 206,747,898

Capital Recovery Factor (CRF)2

0.08 0.08

Annual Costs3

Unit 1 Unit 2

Fixed O&M Costs 608,000 608,000

Variable O&M Costs 2,836,000 2,858,000

Annualized Capital Cost 18,561,397 16,661,070

Total Annual Costs 22,005,397 20,127,070

4: The variable O&M cost estimates are based on the cost estimates provided by Sargent & Lundy in the 5/16/2013 NOx Control

Technology Cost and Performance Study. Adding LNB/OFA to SCR makes the variable O&M costs less than that of SCR alone

due to a lower NOx concentration and resulting less reagent usage.

1: The installed capital cost estimates for LNB/OFA + SCR are based on the installed capital cost estimates for each unit as

provided by Sargent & Lundy in the 5/16/2013 NOx Control Technology Cost and Performance Study (Unit 1 = $202,601,000 and

Unit 2 = $178,240,000) plus additional cost not accounted for in the S&L cost estimate, including cost for permitting and

legal/regulatory support (estimated by Entergy to be $450,000 for each unit), cost for Entergy employee labor and loaders

(estimated by Entergy to be $6,725,610 for each unit), and cost for capital suspense (estimated by Entergy to be $20,552,528 for

Unit 1 and $21,332,288 for Unit 2 ) .

2: CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment life

 Equipment CRF, 30-yr actual service life, 7% interest

3: The fixed O&M cost estimates are based on the cost estimates provided by Sargent & Lundy in the 5/16/2013 NOx Control

Technology Cost and Performance Study.
Entergy Trinity Consultants

BART Analysis – White Bluff

APPENDIX B

BASELINE VISIBILITY IMPAIRMENT BY POLLUTANT

The following tables are a continuation of the information presented in Tables 4-2 through 4-4.

Tables B-1 through B-3 shows the delta deciview by pollutant in a percentage format.
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BART Analysis – White Bluff

TABLE B-1. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-01 BY POLLUTANT

Year

Maximum

ǻdv)

98th

Percentile

ǻdv)

No. of

Day with

ǻdv  0.5

98th

Percentile

% SO4

98th

Percentile

% NO3

98th

Percentile

% PM10

98th

Percentile

% NO2

Caney Creek Wilderness

2001 2.956 1.628 41 79.06 20.65 0.16 0.12

2002 2.111 1.386 30 47.73 47.56 0.82 3.90

2003 4.194 1.13 35 63.88 34.05 0.30 1.76

Upper Buffalo Wilderness

2001 2.339 1.128 34 74.05 25.72 0.23 0.00

2002 1.544 0.818 18 83.19 16.22 0.34 0.26

2003 1.900 1.140 25 97.99 1.80 0.22 0.00

Hercules Glades Wilderness

2001 1.737 1.041 28 92.29 7.51 0.21 0.00

2002 1.288 0.617 13 78.93 20.76 0.23 0.08

2003 2.230 0.786 20 88.91 10.87 0.21 0.00

Mingo Wilderness

2001 1.569 0.887 18 93.36 6.03 0.33 0.28

2002 1.012 0.750 24 56.89 42.59 0.25 0.28

2003 1.114 0.702 14 63.85 34.84 0.38 0.94

TABLE B-2. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-02 BY POLLUTANT

Year

Maximum

ǻdv)

98th

Percentile

ǻdv)

No. of

Day with

ǻdv  0.5

98th

Percentile

% SO4

98th

Percentile

% NO3

98th

Percentile

% PM10

98th

Percentile

% NO2

Caney Creek Wilderness

2001 3.199 1.695 41 76.22 23.49 0.16 0.14

2002 2.270 1.481 33 65.10 31.38 0.73 2.80

2003 4.437 1.169 38 50.94 47.45 0.31 1.31

Upper Buffalo Wilderness

2001 2.385 1.185 35 70.85 28.92 0.23 0.00

2002 1.618 0.846 20 80.92 18.47 0.31 0.30

2003 1.998 1.176 25 81.45 18.30 0.24 0.00

Hercules Glades Wilderness

2001 1.838 1.060 30 91.12 8.68 0.20 0.00

2002 1.340 0.643 14 76.19 23.50 0.21 0.09

2003 2.263 0.806 21 87.28 12.51 0.21 0.00

Mingo Wilderness

2001 1.701 0.903 18 92.36 6.99 0.31 0.33

2002 1.031 0.805 25 83.70 16.04 0.22 0.03

2003 1.150 0.750 14 60.22 38.39 0.35 1.04
Entergy Trinity Consultants

BART Analysis – White Bluff

TABLE B-3. BASELINE VISIBILITY IMPAIRMENT ATTRIBUTABLE TO SN-05 BY POLLUTANT

Year

Maximum

ǻdv)

98th

Percentile

ǻdv)

No. of

Day with

ǻdv  0.5

98th

Percentile

% SO4

98th

Percentile

% NO3

98th

Percentile

% PM10

98th

Percentile

% NO2

Caney Creek Wilderness

2001 0.028 0.008 0 12.12 82.96 1.17 2.01

2002 0.020 0.005 0 13.56 82.08 0.17 3.94

2003 0.036 0.010 0 15.90 76.81 1.12 4.55

Upper Buffalo Wilderness

2001 0.014 0.004 0 18.99 77.59 1.36 0.12

2002 0.009 0.004 0 22.05 75.33 1.01 0.12

2003 0.013 0.005 0 17.05 74.39 1.76 4.31

Hercules Glades Wilderness

2001 0.007 0.004 0 15.47 80.65 0.89 1.68

2002 0.006 0.003 0 30.17 65.62 1.50 0.49

2003 0.008 0.004 0 60.26 33.74 2.40 0.03

Mingo Wilderness

2001 0.009 0.003 0 12.83 84.94 0.89 0.06

2002 0.019 0.008 0 11.22 84.34 1.02 1.91

2003 0.015 0.003 0 21.56 77.36 0.43 0.05
Entergy Trinity Consultants

BART Analysis – White Bluff

APPENDIX C

CALMET MODELING PROTOCOL

As stated in Section 3.1, the meteorological data used in the analyses presented in this report was

originally developed in 2007 and was first used in a BART determination for Oklahoma Gas &

Electric. Because the development of a set of CALMET/CALPUFF meteorological data is so

intensive, this same dataset has been used numerous times since 2007 for various other BART

projects in EPA Region 6. The protocol that accompanied the original development has followed the

dataset in each case and is doing so here again.
CALMET DATA PROCESSING PROTOCOL  BART DETERMINATION

OKLAHOMA GAS & ELECTRIC

MUSKOGEE GENERATING STATION

SEMINOLE GENERATING STATION

SOONER GENERATING STATION

Prepared by:

Vern Choquette  Principal Consultant

Eugene Chen, PE  Senior Consultant

Jeremy Townley  Consultant

TRINITY CONSULTANTS

120 East Sheridan

Suite 205

Oklahoma City, OK 73104

(405) 228-3292

January 23, 2008

Project 083701.0004
OG&E i Trinity Consultants

CALMET Processing Protocol 083701.0004

TABLE OF CONTENTS

1. INTRODUCTION.................................................................................................... 1-1

1.1 BEST AVAILABLE RETROFIT TECHNOLOGY RULE BACKGROUND ......................... 1-1

1.2 OBJECTIVE ............................................................................................................ 1-2

1.3 LOCATION OF SOURCES AND RELEVANT CLASS I AREAS...................................... 1-2

2. CALPUFF MODEL SYSTEM ............................................................................... 2-1

2.1 MODEL VERSIONS................................................................................................. 2-1

2.2 MODELING DOMAIN ............................................................................................. 2-1

3. CALMET............................................................................................................ 3-1

3.1 GEOPHYSICAL DATA............................................................................................. 3-1

3.1.1 TERRAIN DATA ...................................................................................................3-1

3.1.2 LAND USE DATA.................................................................................................3-2

3.1.3 COMPILING TERRAIN AND LAND USE DATA.......................................................3-3

3.2 METEOROLOGICAL DATA ..................................................................................... 3-3

3.2.1 MESOSCALE MODEL METEOROLOGICAL DATA .................................................3-3

3.2.2 SURFACE METEOROLOGICAL DATA ...................................................................3-4

3.2.3 UPPER AIR METEOROLOGICAL DATA.................................................................3-5

3.2.4 PRECIPITATION METEOROLOGICAL DATA..........................................................3-6

3.2.5 BUOY METEOROLOGICAL DATA.........................................................................3-7

3.3 CALMET CONTROL PARAMETERS....................................................................... 3-8

3.3.1 VERTICAL METEOROLOGICAL PROFILE..............................................................3-8

3.3.2 INFLUENCES OF OBSERVATIONS .........................................................................3-9

APPENDIX A- METEOROLOGICAL STATIONS

APPENDIX B – SAMPLE CALMET CONTROL FILE (CALPUFF VERSION 5.8)

APPENDIX C – SAMPLE CALMET CONTROL FILE (CALPUFF VERSION 6)
OG&E ii Trinity Consultants

CALMET Processing Protocol 083701.0004

LIST OF TABLES

TABLE 1-1. BART-ELIGIBLE SOURCES ...............................................................................................1-2

TABLE 1-2. DISTANCE FROM STATION TO SURROUNDING CLASS I AREAS .......................................1-2

TABLE 2-1. CALPUFF MODELING SYSTEM VERSIONS .....................................................................2-1

TABLE 3-1. VERTICAL LAYERS OF THE CALMET METEOROLOGICAL DOMAIN................................3-9

TABLE A-1. LIST OF SURFACE METEOROLOGICAL STATIONS ...........................................................A-1

TABLE A-2. LIST OF UPPER AIR METEOROLOGICAL STATIONS.........................................................A-5

TABLE A-3. LIST OF PRECIPITATION METEOROLOGICAL STATIONS..................................................A-6

TABLE A-4. LIST OF OVER WATER METEOROLOGICAL STATIONS..................................................A-14
OG&E iii Trinity Consultants

CALMET Processing Protocol 083701.0004

LIST OF FIGURES

FIGURE 1-1. PLOT OF SOURCES AND NEAREST CLASS I AREAS .........................................................1-3

FIGURE 2-1. REFINED METEOROLOGICAL MODELING DOMAIN.........................................................2-2

FIGURE 3-1. PLOT OF LAND ELEVATION USING USGS TERRAIN DATA ............................................3-2

FIGURE 3-2. PLOT OF LAND USE USING USGS LULC DATA.............................................................3-3

FIGURE 3-3. PLOT OF SURFACE STATION LOCATIONS........................................................................3-5

FIGURE 3-4. PLOT OF UPPER AIR STATIONS LOCATIONS ...................................................................3-6

FIGURE 3-5. PLOT OF PRECIPITATION METEOROLOGICAL STATIONS .................................................3-7

FIGURE 3-6. PLOT OF BUOY METEOROLOGICAL STATIONS ................................................................3-8
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CALMET Processing Protocol 083701.0004

1. INTRODUCTION

Oklahoma Gas & Electric (OG&E) owns and operates three electric generating stations near

Muskogee, Oklahoma (Muskogee Generating Station), Seminole, Oklahoma (Seminole Generating 

Station), and Stillwater, Oklahoma (Sooner Generating Station). These generating stations are

considered eligible to be regulated under the U.S. Environmental Protection Agency’s (EPA) Best 

Available Retrofit Technology (BART) provisions of the Regional Haze Rule. This protocol 

describes the proposed methodology for conducting the CALMET data processing for the refined 

CALPUFF BART modeling analysis for OG&E’s Muskogee, Seminole, and Sooner Generating 

Stations. A detailed CALPUFF BART modeling protocol will be submitted in the near future and 

will include a discussion of the CALPUFF parameters as well as the post processing methodologies 

to be used in the refined modeling analysis for each station.

1.1 BEST AVAILABLE RETROFIT TECHNOLOGY RULE BACKGROUND

On July 1, 1999, the U.S. Environmental EPA published the final Regional Haze Rule (RHR). The 

objective of the RHR is to improve visibility in 156 specific areas across with United States, known 

as Class I areas. The Clean Air Act defines Class I areas as certain national parks (over 6000 acres), 

wilderness areas (over 5000 acres), national memorial parks (over 5000 acres), and international 

parks that were in existence on August 7, 1977.

On July 6, 2005, the EPA published amendments to its 1999 RHR, often called the BART rule, which 

included guidance for making source-specific Best Available Retrofit Technology (BART) 

determinations. The BART rule defines BART-eligible sources as sources that meet the following 

criteria: 

(1) Have potential emissions of at least 250 tons per year of a visibility-impairing pollutant,

(2) Began operation between August 7, 1962 and August 7, 1977, and

(3) Are listed as one of the 26 listed source categories in the guidance.

A BART-eligible source is not automatically subject to BART. Rather, BART-eligible sources are 

subject-to-BART if the sources are “reasonably anticipated to cause or contribute to visibility 

impairment in any federal mandatory Class I area.” EPA has determined that sources are reasonably 

anticipated to cause or contribute to visibility impairment if the visibility impacts from a source are 

greater than 0.5 deciviews (dv) when compared against a natural background.

Air quality modeling is the tool that is used to determine a source’s visibility impacts. States have the 

authority to exempt certain BART-eligible sources from installing BART controls if the results of the 

dispersion modeling demonstrate that the source cannot reasonably be anticipated to cause or 

contribute to visibility impairment in a Class I area. Further, states also have the authority to define 

the modeling procedures for conducting modeling related to making BART determinations. 
OG&E 1-2 Trinity Consultants

CALMET Processing Protocol 083701.0004

1.2 OBJECTIVE

The objective of this document is to provide a protocol summarizing the modeling methods and 

procedures that will be followed to conduct the CALMET data processing necessary to complete a

refined CALPUFF modeling analysis for the OG&E generating stations discussed above. The 

modeling methods and procedures contained in this protocol and the CALPUFF protocol yet to be 

submitted will be used to determine appropriate controls for OG&E’s BART-eligible sources that can 

reasonably be anticipated to reduce the sources’ effects on or contribution to visibility impairment in 

the surrounding Class I areas. It is OG&E’s intent to determine a combination of emissions controls 

that will reduce the impact of each generating station to a degree that the 98th percentile of the 

visibility impact predicted by the model due to all the BART eligible sources at each station 

collectively is below EPA’s recommended visibility contribution threshold of 0.5 dv.

1.3 LOCATION OF SOURCES AND RELEVANT CLASS I AREAS

The sources listed in Table 1-1 are the sources that have been identified by OG&E as sources that 

meet the three criteria for BART-eligible sources.

TABLE 1-1. BART-ELIGIBLE SOURCES

EPN Description

Muskogee Sources

Unit 4 5,480 MMBtu/hr Coal Fired Boiler

Unit 5 5,480 MMBtu/hr Coal Fired Boiler

Seminole Sources

SM1 5,480 MMBtu/hr Natural Gas Fired Boiler

SM2 5,480 MMBtu/hr Natural Gas Fired Boiler

SM3 5,496 MMBtu/hr Natural Gas Fired Boiler

Sooner Sources

Unit 1 5,116 MMBtu/hr Coal Fired Boiler

Unit 2 5,116 MMBtu/hr Coal Fired Boiler

As required in CENRAP’s BART Modeling Guidelines, Class I areas within 300 km of each station 

will be included in each analysis. The following table summarizes the distances of the four closest 

Class I areas to each station. As seen from this summary, some Class I areas are more than 300 km 

from the certain stations. However, in order to demonstrate that each station will not have an adverse 

effect on the visibility at any of the four nearest Class I areas, OG&E has opted to include those Class 

I areas more than 300 km away in this analysis. Note that the distances listed in the table below are 

the distances between the stations and the closest border of the Class I areas. 

TABLE 1-2. DISTANCE FROM STATION TO SURROUNDING CLASS I AREAS

CACR HEGL UPBU WIMO

Muskogee 180 230 164 324

Seminole 242 386 310 178

Sooner 345 363 327 234
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A plot of the Class I areas with respect to the each station is provided in Figure 1-1.

 FIGURE 1-1. PLOT OF SOURCES AND NEAREST CLASS I AREAS

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas
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2. CALPUFF MODEL SYSTEM

The main components of the CALPUFF modeling system are CALMET, CALPUFF, and CALPOST. 

CALMET is the meteorological model that generates hourly three-dimensional meteorological fields 

such as wind and temperature. CALPUFF simulates the non-steady state transport, dispersion, and 

chemical transformation of air pollutants emitted from a source in “puffs”. CALPUFF calculates 

hourly concentrations of visibility affecting pollutants at each specified receptor in a modeling 

domain. CALPOST is the post-processor for CALPUFF that computes visibility impacts from a 

source based on the visibility affecting pollutant concentrations that were output by CALPUFF.

2.1 MODEL VERSIONS

The versions of the CALPUFF modeling system programs that are proposed for conducting OG&E’s 

BART modeling are listed in Table 2-1. A detailed refined CALPUFF BART modeling protocol will 

be submitted in the near future.

TABLE 2-1. CALPUFF MODELING SYSTEM VERSIONS

Processor Version Level

TERREL 3.3 030402

CTGCOMP 2.21 030402

CTGPROC 2.63 050128

MAKEGEO 2.2 030402

CALMET 5.53a 040716

CALPUFF 5.8 070623

POSTUTIL 1.3 030402

CALPOST 5.51 030709

2.2 MODELING DOMAIN

The CALPUFF modeling system utilizes three modeling grids: the meteorological grid, the 

computational grid, and the sampling grid. The meteorological grid is the system of grid points at 

which meteorological fields are developed with CALMET. The computational grid determines the 

computational area for a CALPUFF run. Puffs are advected and tracked only while within the 

computational grid. The meteorological grid is defined so that it covers the areas of concern and 

gives enough marginal buffer area for puff transport and dispersion. A plot of the proposed 

meteorological modeling domain with respect to the Class I areas being modeled is also provided in 
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Figure 2-1. The computational domain will be set to extend at least 50 km in all directions beyond 

the Muskogee, Seminole, and Sooner Generating Stations and the Class I areas of interest. Note that 

the map projection for the modeling domain will be Lambert Conformal Conic (LCC) and the datum 

will be the World Geodetic System 84 (WGS-84). The reference point for the modeling domain is

Latitude 40oN, Longitude 97oW. The southwest corner will be set to -951.547 km LCC, -1646.637 

km LCC corresponding to Latitude 24.813 oN and Longitude 87.778oW. The meteorological grid 

spacing will be 4 km, resulting in 462 grid points in the X direction and 376 grid points in the Y 

direction.

FIGURE 2-1. REFINED METEOROLOGICAL MODELING DOMAIN

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

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k

)m

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Meteorological Modeling Domain

Computational Modeling Domain 1
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3. CALMET

The EPA Approved Version of the CALMET meteorological processor will be used to generate the 

meteorological data for CALPUFF. CALMET is the meteorological processor that compiles 

meteorological data from raw observations of surface and upper air conditions, precipitation 

measurements, mesoscale model output, and geophysical parameters into a single hourly, gridded 

data set for input into CALPUFF. CALMET will be used to assimilate data for 2001- 2003 using 

National Weather Service (NWS) surface station observations, upper air station observations, 

precipitation station observations, buoy station observations (for overwater areas), and mesoscale 

model output to develop the meteorological field. 

3.1 GEOPHYSICAL DATA

CALMET requires geophysical data to characterize the terrain and land use parameters that 

potentially affect dispersion. Terrain features affect flows and create turbulence in the atmosphere 

and are potentially subjected to higher concentrations of elevated puffs. Different land uses exhibit 

variable characteristics such as surface roughness, albedo, Bowen ratio, and leaf-area index that also 

effect turbulence and dispersion. 

3.1.1 TERRAIN DATA

Terrain data will be obtained from the United States Geological Survey (USGS) in 

1-degree (1:250,000 scale or approximately 90 meter resolution) digital format. The

USGS terrain data will then be processed by the TERREL program to generate grid-cell 

elevation averages across the modeling domain. A plot of the land elevations based on the 

USGS data for the modeling domain is provided in Figure 3-1.
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FIGURE 3-1. PLOT OF LAND ELEVATION USING USGS TERRAIN DATA

3.1.2 LAND USE DATA

The land use land cover (LULC) data from the USGS North American land cover 

characteristics data base in the Lambert Azimuthal equal area map projection will be used 

in order to determine the land use within the modeling domain. The LULC data will be 

processed by the CTGPROC program which will generate land use for each grid cell 

across the modeling domain. A plot of the land use based on the USGS data for the 

modeling domain is provided in Figure 3-2.

-800 -600 -400 -200 0 200 400 600 800

LCC Easting(km)

-1600

-1400

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Seminole Station

Muskogee Station

Sooner Station

0

982

1960

2950

3930

Terrain 

Elevation (m)
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FIGURE 3-2. PLOT OF LAND USE USING USGS LULC DATA

3.1.3 COMPILING TERRAIN AND LAND USE DATA

The terrain data files output by the TERELL program and the LULC files output by the 

CTGPROC program will be uploaded into the MAKEGEO program to create a 

geophysical data file that will be input into CALMET. 

3.2 METEOROLOGICAL DATA 

CALMET will be used to assimilate data for 2001, 2002, and 2003 using mesoscale model output and 

National Weather Service (NWS) surface station observations, upper air station observations,

precipitation station observations, and National Oceanic and Atmosphere Administrations (NOAA) 

buoy station observations to develop the meteorological field. 

3.2.1 MESOSCALE MODEL METEOROLOGICAL DATA

Hourly mesoscale data will also be used as the initial guess field in developing the 

CALMET meteorological data. It is OG&E’s intent to use the following 5th generation 

mesoscale model meteorological data sets (or MM5 data) in the analysis:

 2001 MM5 data at 12 km resolution generated by the U.S. EPA 

 2002 MM5 data at 36 km resolution generated by the Iowa DNR

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

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27.5

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62.5

80

Land Use

Sooner Station

Muskogee Station

Seminole Station
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 2003 MM5 data set at 36 km resolution generated by the Midwest RPO

The specific MM5 data that will be used are subsets of the data listed above. As the 

contractor to CENRAP for developing the meteorological data sets for the BART 

modeling, Alpine Geophysics extracted three subsets of MM5 data for each year from 

2001 to 2003 from the data sets listed above using the CALMM5 extraction program. The 

three subsets covered the northern, central, and southern portions of CENRAP. TXI is 

proposing to use the southern set of the extracted MM5 data. 

The 2001 southern subset of the extracted MM5 data includes 30 files that are broken into 

10 to 11 day increments (3 files per month). The 2002 and 2003 southern subsets of 

extracted MM5 data include 12 files each of which are broken into 30 to 31 day increment

files (1 file per month). Note that the 2001 to 2003 MM5 data extracted by Alpine

Geophysics will not be able to be used directly in the modeling analysis. To run the Alpine 

Geophysics extracted MM data in the EPA approved CALMET program, each of the MM5 

files will need to be adjusted by appending an additional six (6) hours, at a minimum, to 

the end of each file to account for the shift in time zones from the Greenwich Mean Time 

(GMT) prepared Alpine Geophysics data to Time Zone 6 for this analysis. No change to 

the data will occur. 

The time periods covered by the data in each of the MM5 files extracted by Alpine 

Geophysics include a specific number of calendar days, where the data starts at Hour 0 in 

GMT for the first calendar day and ends at Hour 23 in GMT on the last calendar day. In 

order to run CALMET in the local standard time (LST), which is necessary since the 

surface meteorological observations are recorded in LST, there must be hours of MM5 data 

referenced in a CALMET run that match the LST observation hours. Since the LST hours 

in Central Standard Time (CST) are 6 hours behind GMT, it is necessary to adjust the data 

in each MM5 file so that the time periods covered in the files match CST. 

Based on the above discussion, the Alpine Geophysics MM5 data will not be used directly. 

Instead the data files will be modified to add 8 additional hours of data to the end of each

file from the beginning of the subsequent file. CALMET will then be run using the 

appended MM5 data to generate a contiguous set of CALMET output files. The converted 

MM5 data files occupy approximately 1.2 terabytes (TB) of hard drive space.

3.2.2 SURFACE METEOROLOGICAL DATA

Parameters affecting turbulent dispersion that are observed hourly at surface stations 

include wind speed and direction, temperature, cloud cover and ceiling, relative humidity, 

and precipitation type. It is OG&E’s intent to use the surface stations listed in Table A-1 

of Appendix A. The locations of the surface stations with respect to the modeling domain 

are shown in Figure 3-3. The stations were selected from the available data inventory to 

optimize spatial coverage and representation of the domain. Data from the stations will be 

processed for use in CALMET using EPA’s SMERGE program.
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FIGURE 3-3. PLOT OF SURFACE STATION LOCATIONS

3.2.3 UPPER AIR METEOROLOGICAL DATA

Observations of meteorological conditions in the upper atmosphere provide a profile of 

turbulence from the surface through the depth of the boundary layer in which dispersion 

occurs. Upper air data are collected by balloons launched simultaneously across the 

observation network at 0000 Greenwich Mean Time (GMT) (6 o’clock PM in Oklahoma) 

and 1200 GMT (6 o’clock AM in Oklahoma). Sensors observe pressure, wind speed and 

direction, and temperature (among other parameters) as the balloon rises through the 

atmosphere. The upper air observation network is less dense than surface observation 

points since upper air conditions vary less and are generally not as affected by local effects 

(e.g., terrain or water bodies). The upper air stations that are proposed for this analysis are 

listed in Table A-2 of Appendix A. The locations of the upper air stations with respect to 

the modeling domain are shown in Figure 3-4. These stations were selected from the 

available data inventory to optimize spatial coverage and representation of the domain. 

Data from the stations will be processed for use in CALMET using EPA’s READ62 

program.

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

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Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Surface Stations
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FIGURE 3-4. PLOT OF UPPER AIR STATIONS LOCATIONS

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

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-1400

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-800

-600

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LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Upper Air Stations

3.2.4 PRECIPITATION METEOROLOGICAL DATA

The effects of chemical transformation and deposition processes on ambient pollutant 

concentrations will be considered in this analysis. Therefore, it is necessary to include 

observations of precipitation in the CALMET analysis. The precipitation stations that are 

proposed for this analysis are listed in Table A-3 of Appendix A. The locations of the 

precipitation stations with respect to the modeling domain are shown in Figure 3-5. These 

stations were selected from the available data inventory to optimize spatial coverage and 

representation of the domain. Data from the stations will be processed for use in 

CALMET using EPA’s PMERGE program.
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FIGURE 3-5. PLOT OF PRECIPITATION METEOROLOGICAL STATIONS

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

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LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Precipitation Stations

3.2.5 BUOY METEOROLOGICAL DATA

The effects of land/sea breeze on ambient pollutant concentrations will be considered in 

this analysis. Therefore, it is necessary to include observations of buoy stations in the 

CALMET analysis. The buoy stations that are proposed for this analysis are listed in Table 

A-4 of Appendix A. The locations of the buoy stations with respect to the modeling 

domain are shown in Figure 3-6. These stations were selected from the available data 

inventory to optimize spatial coverage and representation of the domain along the 

coastline. Data from the stations will be prepared by filling missing hour records with the 

CALMET missing parameter value (9999). No adjustments to the data will occur. 
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FIGURE 3-6. PLOT OF BUOY METEOROLOGICAL STATIONS

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Buoy Stations

3.3 CALMET CONTROL PARAMETERS

Appendix B provides a sample CALMET input file used in OG&E’s modeling analysis. A few 

details of the CALMET model setup for sensitive parameters are also discussed below. 

3.3.1 VERTICAL METEOROLOGICAL PROFILE

The height of the top vertical layer will be set to 3,500 meters. This height corresponds to 

the top sounding pressure level for which upper air observation data will be relied upon. 

The vertical dimension of the domain will be divided into 12 layers with the maximum 

elevations for each layer shown in Table 3-1. The vertical dimensions are weighted 

towards the surface to resolve the mixing layer while using a somewhat coarser resolution 

for the layers aloft. 
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TABLE 3-1. VERTICAL LAYERS OF THE CALMET METEOROLOGICAL DOMAIN

Layer Elevation (m)

1 20 

2 40

3 60

4 80

5 100

6 150

7 200

8 250

9 500

10 1000

11 2000

12 3500

CALMET allows for a bias value to be applied to each of the vertical layers. The bias 

settings for each vertical layer determine the relative weight given to the vertically 

extrapolated surface and upper air wind and temperature observations. The initial guess 

fields are computed with an inverse distance weighting (1/r

2

) of the surface and upper air 

data. The initial guess fields may be modified by a layer dependent bias factor. Values for 

the bias factor may range from -1 to +1. A bias of -1 eliminates upper-air observations in

the 1/r2interpolations used to initialize the vertical wind fields. Conversely, a bias of +1 

eliminates the surface observations in the interpolations for this layer. Normally, bias is set 

to zero (0) for each vertical layer, such that the upper air and surface observations are given 

equal weight in the 1/r2interpolations. The biases for each layer of the proposed modeling 

domain will be set to zero.

CALMET allows for vertical extrapolation of surface wind observations to layers aloft to 

be skipped if the surface station is close to the upper air station. Alternatively, CALMET 

allows data from all surface stations to be extrapolated. The CALMET parameter that 

controls this setting is IEXTRP. Setting IEXTRP to a value less than zero (0) means that 

layer 1 data from upper air soundings is ignored in any vertical extrapolations. IEXTRP 

will be set to -4 for this analysis (i.e., the similarity theory is used to extrapolate the surface 

winds into the layers aloft, which provides more information on observed local effects to 

the upper layers).

3.3.2 INFLUENCES OF OBSERVATIONS

Step 1 wind fields will be based on an initial guess using MM5 data and refined to reflect 

terrain affects. Step 2 wind fields will adjust the Step 1 wind field by incorporating the 

influence of local observations. An inverse distance method is used to determine the 

influence of observations to the Step 1 wind field. RMAX1 and RMAX2 define the radius 

of influence for data from surface stations to land in the surface layer and data from upper 

air stations to land in the layers aloft. In general, RMAX1 and RMAX2 are used to 

exclude observations from being inappropriately included in the development of the Step 2
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wind field if the distance from an observation station to a grid point exceeds the maximum 

radius of influence. 

If the distance from an observation station to a grid point is less than the value set for 

RMAX, the observation data will be used in the development of the Step 2 wind field. R1 

represents the distance from a surface observation station at which the surface observation 

and the Step 1 wind field are weighted equally. R2 represents the comparable distance for 

winds aloft. R1 and R2 are used to weight the observation data with respect to the MM5 

data that was used to generate the Step 1 wind field. Large values for R1 and R2 give 

more weight to the observations, where as small values give more weight to the MM5 data. 

In this BART modeling analysis, RMAX 1 will be set to 20 km, and R1 will be set to 10 

km. This will limit the influence of the surface observation data from all surface stations to 

20 km from each station, and will equally weight the MM5 and observation data at 10 km. 

RMAX2 will be set to 50 km, and R2 will be set to 25 km. This will limit the influence of 

the upper air observation data from all surface stations to 50 km from each station, and will 

equally weight the MM5 and observation data at 25 km. These settings of radius of 

influence will allow for adequate weighting of the MM5 data and the observation data 

across the modeling domain due to the vast domain to be modeled. RAMX 3 will be set to 

500 km. 
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APPENDIX A- METEOROLOGICAL STATIONS

TABLE A-1. LIST OF SURFACE METEOROLOGICAL STATIONS

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC North

(km) Long Lat

1 KDYS 69019 -267.672 -834.095 96.9968 39.9925

2 KNPA 72222 932.565 -1020.909 97.0110 39.9908

3 KBFM 72223 857.471 -996.829 97.0101 39.9910

4 KGZH 72227 946.767 -899.515 97.0112 39.9919

5 KTCL 72228 870.843 -706.104 97.0103 39.9936

6 KNEW 53917 674.172 -1078.342 97.0080 39.9903

7 KNBG 12958 677.719 -1104.227 97.0080 39.9900

8 BVE 12884 741.996 -1153.463 97.0088 39.9896

9 KPTN 72232 550.88 -1124.295 97.0065 39.9898

10 KMEI 13865 774.911 -814.225 97.0092 39.9926

11 KPIB 72234 728.416 -915.165 97.0086 39.9917

12 KGLH 72235 557.072 -703.097 97.0066 39.9936

13 KHEZ 11111 540.777 -912.22 97.0064 39.9918

14 KMCB 11112 622.755 -949.618 97.0074 39.9914

15 KGWO 11113 640.102 -695.286 97.0076 39.9937

16 KASD 72236 692.381 -1043.261 97.0082 39.9906

17 KPOE 72239 363.294 -984.839 97.0043 39.9911

18 KBAZ 72241 -102.133 -1140.886 96.9988 39.9897

19 KGLS 72242 215.108 -1185.604 97.0025 39.9893

20 KDWH 11114 140.413 -1101.174 97.0017 39.9900

21 KIAH 12960 158.266 -1108.37 97.0019 39.9900

22 KHOU 72243 167.147 -1147.402 97.0020 39.9896

23 KEFD 12906 178.551 -1152.782 97.0021 39.9896

24 KCXO 72244 152.739 -1069.309 97.0018 39.9903

25 KCLL 11115 60.898 -1044.381 97.0007 39.9906

26 KLFK 93987 214.643 -969.355 97.0025 39.9912

27 KUTS 11116 136.056 -1026.773 97.0016 39.9907

28 KTYR 11117 150.451 -846.207 97.0018 39.9924

29 KCRS 72246 56.655 -882.642 97.0007 39.9920

30 KGGG 72247 214.572 -841.163 97.0025 39.9924

31 KGKY 11118 -9.365 -812.25 96.9999 39.9927

32 KDTN 72248 304.827 -821.713 97.0036 39.9926

33 KBAD 11119 312.743 -825.101 97.0037 39.9925

34 KMLU 11120 465.834 -816.211 97.0055 39.9926

35 KTVR 11121 561.446 -840.225 97.0066 39.9924

36 KTRL 11122 68.599 -806.417 97.0008 39.9927

37 KOCH 72249 216.81 -930.252 97.0026 39.9916

38 KBRO 12919 -44.167 -1571.387 96.9995 39.9858
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Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC North

(km) Long Lat

39 KALI 72251 -103.012 -1363.74 96.9988 39.9877

40 KLRD 12920 -246.548 -1381.603 96.9971 39.9875

41 KSSF 72252 -143.386 -1183.35 96.9983 39.9893

42 KRKP 11123 -4.965 -1324.914 96.9999 39.9880

43 KCOT 11124 -219.097 -1280.964 96.9974 39.9884

44 KLBX 11125 150.245 -1207.466 97.0018 39.9891

45 KSAT 12921 -143.024 -1160.935 96.9983 39.9895

46 KHDO 12962 -211.702 -1178.172 96.9975 39.9894

47 KSKF 72253 -154.625 -1177.555 96.9982 39.9894

48 KHYI 11126 -84.156 -1122.487 96.9990 39.9899

49 KTKI 72254 38.788 -754.791 97.0005 39.9932

50 KBMQ 11127 -118.39 -1027.031 96.9986 39.9907

51 KATT 11128 -67.587 -1075.97 96.9992 39.9903

52 KSGR 11129 131.478 -1151.702 97.0016 39.9896

53 KGTU 11130 -65.624 -1033.173 96.9992 39.9907

54 KVCT 12912 6.587 -1236.788 97.0001 39.9888

55 KPSX 72255 73.878 -1253.33 97.0009 39.9887

56 KACT 13959 -22.12 -929.156 96.9997 39.9916

57 KPWG 72256 -30.147 -944.073 96.9996 39.9915

58 KILE 72257 -65.288 -988.507 96.9992 39.9911

59 KGRK 11131 -79.643 -990.173 96.9991 39.9911

60 KTPL 11132 -38.203 -981.19 96.9996 39.9911

61 KPRX 13960 143.317 -703.663 97.0017 39.9936

62 KDTO 72258 -17.018 -752.974 96.9998 39.9932

63 KAFW 11133 -29.564 -777.061 96.9997 39.9930

64 KFTW 72259 -34.302 -795.502 96.9996 39.9928

65 KMWL 11134 -99.769 -798.767 96.9988 39.9928

66 KRBD 11135 12.453 -810.467 97.0002 39.9927

67 KDRT 11136 -384.069 -1170.59 96.9955 39.9894

68 KFST 22010 -566.418 -988.838 96.9933 39.9911

69 KGDP 72261 -739.127 -873.302 96.9913 39.9921

70 KSJT 72262 -333.338 -952.54 96.9961 39.9914

71 KMRF 23034 -676.265 -1042.616 96.9920 39.9906

72 KMAF 72264 -489.668 -878.107 96.9942 39.9921

73 KINK 23023 -586.882 -890.654 96.9931 39.9920

74 KABI 72265 -252.044 -836.353 96.9970 39.9924

75 KLBB 13962 -445.006 -689.313 96.9948 39.9938

76 KATS 11137 -696.818 -763.258 96.9918 39.9931

77 KCQC 11138 -785.757 -515.724 96.9907 39.9953

78 KROW 23009 -698.822 -712.898 96.9918 39.9936

79 KSRR 72268 -789.593 -686.226 96.9907 39.9938

80 KCNM 11139 -682.79 -822.109 96.9919 39.9926

81 KALM 36870 -838.056 -752.338 96.9901 39.9932

82 KLRU 72269 -931.527 -804.112 96.9890 39.9927

83 KTCS 72271 -952.353 -695.469 96.9888 39.9937
OG&E A-3 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC North

(km) Long Lat

84 KSVC 93063 -1042.03 -752.033 96.9877 39.9932

85 KDMN 72272 -1006.77 -799.231 96.9881 39.9928

86 KMSL 72323 854.846 -536.687 97.0101 39.9952

87 KPOF 72330 578.62 -336.733 97.0068 39.9970

88 KGTR 11140 779.065 -689.108 97.0092 39.9938

89 KTUP 93862 753.875 -600.337 97.0089 39.9946

90 KMKL 72334 727.051 -454.383 97.0086 39.9959

91 KLRF 72340 440.654 -550.661 97.0052 39.9950

92 KHKA 11141 643.365 -424.419 97.0076 39.9962

93 KHOT 72341 358.094 -604.603 97.0042 39.9945

94 KTXK 11142 278.022 -720.623 97.0033 39.9935

95 KLLQ 72342 488.655 -698.008 97.0058 39.9937

96 KMWT 72343 254.18 -599.224 97.0030 39.9946

97 KFSM 13964 237.97 -512.87 97.0028 39.9954

98 KSLG 72344 224.881 -419.064 97.0027 39.9962

99 KVBT 11143 248.074 -399.892 97.0029 39.9964

100 KHRO 11144 343.525 -405.601 97.0041 39.9963

101 KFLP 11145 404.239 -399.142 97.0048 39.9964

102 KBVX 11146 480.712 -457.853 97.0057 39.9959

103 KROG 11147 258.44 -397.685 97.0031 39.9964

104 KSPS 13966 -138.053 -664.886 96.9984 39.9940

105 KHBR 72352 -186.121 -551.123 96.9978 39.9950

106 KCSM 11148 -198.844 -513.911 96.9977 39.9954

107 KFDR 11149 -181.653 -625.205 96.9979 39.9944

108 KGOK 72353 -35.905 -458.97 96.9996 39.9959

109 KTIK 72354 -34.581 -506.938 96.9996 39.9954

110 KPWA 11150 -58.596 -493.951 96.9993 39.9955

111 KSWO 11151 -7.42 -425.828 96.9999 39.9962

112 KMKO 72355 146.972 -479.879 97.0017 39.9957

113 KRVS 72356 91.059 -438.276 97.0011 39.9960

114 KBVO 11152 87.136 -357.069 97.0010 39.9968

115 KMLC 11153 110.647 -563.566 97.0013 39.9949

116 KOUN 72357 -40.731 -527.298 96.9995 39.9952

117 KLAW 11154 -129.405 -600.222 96.9985 39.9946

118 KCDS 72360 -300.297 -610.668 96.9965 39.9945

119 KGNT 72362 -985.117 -475.563 96.9884 39.9957

120 KGUP 11155 -1059.48 -427.151 96.9875 39.9961

121 KAMA 23047 -425.319 -518.171 96.9950 39.9953

122 KBGD 72363 -395.603 -466.083 96.9953 39.9958

123 KFMN 72365 -993.449 -297.944 96.9883 39.9973

124 KSKX 72366 -770.464 -355.855 96.9909 39.9968

125 KTCC 23048 -597.271 -511.241 96.9930 39.9954

126 KLVS 23054 -732.565 -448.329 96.9914 39.9960

127 KEHR 72423 812.573 -199.695 97.0096 39.9982

128 KEVV 93817 822.929 -172.715 97.0097 39.9984
OG&E A-4 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC North

(km) Long Lat

129 KMVN 72433 704.666 -154.54 97.0083 39.9986

130 KMDH 11156 676.745 -218.041 97.0080 39.9980

131 KBLV 11157 617.659 -136.018 97.0073 39.9988

132 KSUS 3966 547.898 -130.122 97.0065 39.9988

133 KPAH 3816 725.985 -293.319 97.0086 39.9974

134 KJEF 72445 419.01 -145.496 97.0050 39.9987

135 KAIZ 11158 387.096 -200.609 97.0046 39.9982

136 KIXD 72447 182.322 -126.913 97.0022 39.9989

137 KWLD 72450 0 -298.57 97.0000 39.9973

138 KAAO 11159 -18.976 -248.773 96.9998 39.9978

139 KIAB 11160 -23.392 -263.471 96.9997 39.9976

140 KEWK 11161 -24.645 -215.58 96.9997 39.9981

141 KGBD 72451 -161.892 -180.781 96.9981 39.9984

142 KHYS 11162 -195.191 -124.723 96.9977 39.9989

143 KCFV 11163 126.442 -319.698 97.0015 39.9971

144 KFOE 72456 114.618 -115.26 97.0014 39.9990

145 KEHA 72460 -432.761 -320.089 96.9949 39.9971

146 KALS 72462 -777.592 -245.892 96.9908 39.9978

147 KDRO 11164 -945.713 -259.163 96.9888 39.9977

148 KLHX 72463 -568.426 -195.178 96.9933 39.9982

149 KSPD 2128 -494.076 -285.176 96.9942 39.9974

150 KCOS 93037 -664.022 -102.596 96.9922 39.9991

151 KGUC 72467 -857.452 -115.301 96.9899 39.9990

152 KMTJ 93013 -940.981 -109.358 96.9889 39.9990

153 KCEZ 72476 -1020.87 -233.14 96.9880 39.9979

154 KCPS 72531 591.652 -136.14 97.0070 39.9988

155 KLWV 72534 808.939 -94.46 97.0096 39.9992

156 KPPF 74543 130.433 -293.855 97.0015 39.9973

157 KHOP 74671 841.751 -324.569 97.0099 39.9971

158 KBIX 74768 778.252 -1028.514 97.0092 39.9907

159 KPQL 11165 814.599 -1019.583 97.0096 39.9908

160 MMPG 76243 -348.007 -1248.779 96.9959 39.9887

161 MMMV 76342 -446.576 -1449.334 96.9947 39.9869

162 MMMY 76394 -316.664 -1581.176 96.9963 39.9857
OG&E A-5 Trinity Consultants

CALMET Processing Protocol 083701.0004

TABLE A-2. LIST OF UPPER AIR METEOROLOGICAL STATIONS

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

1 KABQ 23050 -869.46 -501.713 96.9897 39.9955

2 KAMA 23047 -425.319 -518.171 96.9950 39.9953

3 KBMX 53823 951.609 -702.935 97.0112 39.9936

4 KBNA 13897 920.739 -377.164 97.0109 39.9966

5 KBRO 12919 -44.167 -1571.39 96.9995 39.9858

6 KCRP 12924 -51.535 -1360.35 96.9994 39.9877

7 KDDC 13985 -259.352 -242.681 96.9969 39.9978

8 KDRT 22010 -384.069 -1170.59 96.9955 39.9894

9 KEPZ 3020 -914.558 -852.552 96.9892 39.9923

10 KFWD 3990 -28.034 -793.745 96.9997 39.9928

11 KJAN 3940 650.105 -826.452 97.0077 39.9925

12 KLCH 3937 364.461 -1089.15 97.0043 39.9902

13 KLZK 3952 432.063 -560.441 97.0051 39.9949

14 KMAF 23023 -489.668 -878.107 96.9942 39.9921

15 KOUN 3948 -40.731 -527.298 96.9995 39.9952

16 KSHV 13957 298.869 -831.166 97.0035 39.9925

17 KSIL 53813 698.079 -1054.03 97.0082 39.9905
OG&E A-6 Trinity Consultants

CALMET Processing Protocol 083701.0004

TABLE A-3. LIST OF PRECIPITATION METEOROLOGICAL STATIONS

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

1 ADDI 10063 906.825 -601.428 97.0107 39.9946

2 ALBE 10140 917.606 -821.64 97.0108 39.9926

3 BERR 10748 892.454 -683.388 97.0105 39.9938

4 HALE 13620 881.928 -601.878 97.0104 39.9946

5 HAMT 13645 863.663 -612.725 97.0102 39.9945

6 JACK 14193 898.014 -915.623 97.0106 39.9917

7 MBLE 15478 851.953 -1022.41 97.0101 39.9908

8 MUSC 15749 880.113 -567.484 97.0104 39.9949

9 PETE 16370 935.558 -908.259 97.0110 39.9918

10 THOM 18178 900.858 -915.326 97.0106 39.9917

11 TUSC 18385 895.631 -713.223 97.0106 39.9936

12 VERN 18517 825.585 -685.773 97.0098 39.9938

13 BEEB 30530 462.394 -532.485 97.0055 39.9952

14 BRIG 30900 318.015 -554.857 97.0038 39.9950

15 CALI 31140 419.619 -731.44 97.0050 39.9934

16 CAMD 31152 386.546 -699.659 97.0046 39.9937

17 DIER 32020 268.114 -643.184 97.0032 39.9942

18 EURE 32356 286.738 -390.862 97.0034 39.9965

19 GILB 32794 383.362 -435.625 97.0045 39.9961

20 GREE 32978 450.594 -483.201 97.0053 39.9956

21 STUT 36920 509.943 -596.328 97.0060 39.9946

22 TEXA 37048 278.022 -720.623 97.0033 39.9935

23 ALAM 50130 -749.044 -267.856 96.9912 39.9976

24 ARAP 50304 -441.903 -152.324 96.9948 39.9986

25 COCH 51713 -819.794 -148.582 96.9903 39.9987

26 CRES 51959 -828.107 -119.911 96.9902 39.9989

27 GRAN 53477 -451.781 -203.82 96.9947 39.9982

28 GUNN 53662 -829.573 -141.995 96.9902 39.9987

29 HUGO 54172 -539.364 -81.948 96.9936 39.9993

30 JOHN 54388 -483.95 -201.915 96.9943 39.9982

31 KIM 54538 -544.501 -283.337 96.9936 39.9974

32 MESA 55531 -993.391 -256.696 96.9883 39.9977

33 ORDW 56136 -549.552 -55.741 96.9935 39.9995

34 OURA 56203 -904.197 -168.246 96.9893 39.9985

35 PLEA 56591 -1005.94 -229.472 96.9881 39.9979

36 PUEB 56740 -633.961 -176.872 96.9925 39.9984

37 TYE 57320 -662.095 -242.254 96.9922 39.9978

38 SAGU 57337 -790.269 -176.061 96.9907 39.9984
OG&E A-7 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

39 SANL 57428 -726.777 -285.47 96.9914 39.9974

40 SHEP 57572 -714.046 -252.189 96.9916 39.9977

41 TELL 58204 -920.205 -215.382 96.9891 39.9981

42 TERC 58220 -708.229 -296.023 96.9916 39.9973

43 TRIN 58429 -642.489 -293.805 96.9924 39.9973

44 TRLK 58436 -646.185 -295.727 96.9924 39.9973

45 WALS 58781 -654.989 -262.821 96.9923 39.9976

46 WHIT 58997 -619.615 -250.12 96.9927 39.9977

47 ASHL 110281 684.787 -169.285 97.0081 39.9985

48 CAIR 111166 697.177 -301.436 97.0082 39.9973

49 CARM 111302 772.938 -177.782 97.0091 39.9984

50 CISN 111664 758.146 -151.446 97.0090 39.9986

51 FLOR 113109 751.801 -139.837 97.0089 39.9987

52 HARR 113879 762.044 -246.62 97.0090 39.9978

53 KASK 114629 650.464 -239.886 97.0077 39.9978

54 LAWR 114957 829.038 -128.708 97.0098 39.9988

55 MTCA 115888 827.797 -149.966 97.0098 39.9986

56 MURP 115983 682.261 -251.649 97.0081 39.9977

57 NEWT 116159 766.098 -72.902 97.0090 39.9993

58 REND 117187 731.633 -185.058 97.0086 39.9983

59 SMIT 118020 770.027 -283.638 97.0091 39.9974

60 SPAR 118147 658.275 -185.973 97.0078 39.9983

61 VAND 118781 685.449 -127.048 97.0081 39.9989

62 WEST 119193 778.655 -147.215 97.0092 39.9987

63 EVAN 122738 842.476 -172.871 97.0100 39.9984

64 NEWB 126151 855.854 -223.713 97.0101 39.9980

65 PRIN 127125 836.901 -153.449 97.0099 39.9986

66 STEN 128442 859.099 -156.613 97.0101 39.9986

67 JTML 128967 788.703 -239.572 97.0093 39.9978

68 ARLI 140326 -101.734 -271.373 96.9988 39.9976

69 BAZI 140620 -210.423 -201.758 96.9975 39.9982

70 BEAU 140637 59.762 -288.39 97.0007 39.9974

71 BONN 140957 211.236 -103.29 97.0025 39.9991

72 CALD 141233 -32.689 -330.586 96.9996 39.9970

73 CASS 141351 54.006 -217.645 97.0006 39.9980

74 CENT 141404 170.503 -206.038 97.0020 39.9981

75 CHAN 141427 150.257 -286.094 97.0018 39.9974

76 CLIN 141612 155.623 -157.682 97.0018 39.9986

77 COLL 141730 -265.465 -156.95 96.9969 39.9986

78 COLU 141740 220.541 -316.555 97.0026 39.9971
OG&E A-8 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

79 CONC 141867 58.918 -175.589 97.0007 39.9984

80 DODG 142164 -226.497 -277.655 96.9973 39.9975

81 ELKH 142432 -400.112 -321.784 96.9953 39.9971

82 ENGL 142560 -264.927 -324.066 96.9969 39.9971

83 ERIE 142582 162.669 -291.383 97.0019 39.9974

84 FALL 142686 83.491 -288.177 97.0010 39.9974

85 GALA 142938 -136.931 -176.83 96.9984 39.9984

86 GARD 142980 -304.059 -215.308 96.9964 39.9981

87 GREN 143248 64.308 -307.161 97.0008 39.9972

88 HAYS 143527 -190.307 -161.342 96.9978 39.9985

89 HEAL 143554 -292.133 -175.921 96.9966 39.9984

90 HILL 143686 214.018 -174.006 97.0025 39.9984

91 INDE 143954 139.335 -315.058 97.0016 39.9972

92 IOLA 143984 153.451 -269.438 97.0018 39.9976

93 JOHR 144104 134.784 -203.41 97.0016 39.9982

94 KANO 144178 -50.289 -181.177 96.9994 39.9984

95 KIOW 144341 -113.967 -329.843 96.9987 39.9970

96 MARI 145039 -4.343 -195.712 97.0000 39.9982

97 MELV 145210 137.104 -186.781 97.0016 39.9983

98 MILF 145306 39.504 -106.05 97.0005 39.9990

99 MOUD 145536 152.624 -318.136 97.0018 39.9971

100 OAKL 145888 -306.378 -96.814 96.9964 39.9991

101 OTTA 146128 158.639 -178.635 97.0019 39.9984

102 POMO 146498 143.864 -176.707 97.0017 39.9984

103 SALI 147160 -29.426 -166.908 96.9997 39.9985

104 SMOL 147551 -34.639 -171.31 96.9996 39.9985

105 STAN 147756 225.026 -164.85 97.0027 39.9985

106 SUBL 147922 -303.514 -292.808 96.9964 39.9974

107 TOPE 148167 139.116 -104.91 97.0016 39.9991

108 TRIB 148235 -387.855 -180.643 96.9954 39.9984

109 UNIO 148293 211.43 -272.537 97.0025 39.9975

110 WALL 148535 -376.076 -152.432 96.9956 39.9986

111 WICH 148830 -23.729 -288.579 96.9997 39.9974

112 WILS 148946 -111.502 -156.22 96.9987 39.9986

113 BENT 150611 781.608 -348.109 97.0092 39.9969

114 CALH 151227 865.268 -261.635 97.0102 39.9976

115 CLTN 151631 749.287 -365.634 97.0088 39.9967

116 HERN 153798 859.01 -352.458 97.0101 39.9968

117 MADI 155067 854.116 -265.064 97.0101 39.9976

118 PADU 156110 753.185 -293.024 97.0089 39.9974
OG&E A-9 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

119 PCTN 156580 834.464 -280.496 97.0099 39.9975

120 ALEX 160103 433.824 -959.253 97.0051 39.9913

121 BATN 160549 562.794 -1032.4 97.0066 39.9907

122 CALH 161411 436.113 -817.451 97.0052 39.9926

123 CLNT 161899 578.969 -999.986 97.0068 39.9910

124 JENA 164696 455.225 -912.366 97.0054 39.9918

125 LACM 165078 364.784 -1089.92 97.0043 39.9901

126 MIND 166244 346.708 -812.651 97.0041 39.9927

127 MONR 166314 463.225 -814.905 97.0055 39.9926

128 NATC 166582 369.451 -905.316 97.0044 39.9918

129 SHRE 168440 299.526 -831.143 97.0035 39.9925

130 WINN 169803 408.309 -884.596 97.0048 39.9920

131 BROK 221094 621.827 -914.236 97.0073 39.9917

132 CONE 221900 737.007 -823.513 97.0087 39.9926

133 JAKS 224472 650.361 -826.097 97.0077 39.9925

134 LEAK 224966 805.886 -943.78 97.0095 39.9915

135 MERI 225776 774.942 -814.558 97.0092 39.9926

136 SARD 227815 658.33 -593.661 97.0078 39.9946

137 SAUC 227840 763.399 -1005.93 97.0090 39.9909

138 TUPE 229003 753.571 -600.03 97.0089 39.9946

139 ADVA 230022 657.892 -298.102 97.0078 39.9973

140 ALEY 230088 505.348 -305.864 97.0060 39.9972

141 BOLI 230789 331.651 -291.689 97.0039 39.9974

142 CASV 231383 310.855 -392.187 97.0037 39.9965

143 CLER 231674 575.868 -302.209 97.0068 39.9973

144 CLTT 231711 307.465 -190.83 97.0036 39.9983

145 COLU 231791 421.287 -155.672 97.0050 39.9986

146 DREX 232331 228.23 -185.776 97.0027 39.9983

147 ELM 232568 257.758 -159.419 97.0030 39.9986

148 FULT 233079 470.408 -150.668 97.0056 39.9986

149 HOME 233999 619.93 -415.469 97.0073 39.9962

150 JEFF 234271 424.774 -172.095 97.0050 39.9984

151 JOPL 234315 238.245 -318.262 97.0028 39.9971

152 LEBA 234825 402.239 -276.263 97.0048 39.9975

153 LICK 234919 480.849 -280.775 97.0057 39.9975

154 LOCK 235027 302.048 -300.612 97.0036 39.9973

155 MALD 235207 659.982 -377.876 97.0078 39.9966

156 MARS 235298 332.062 -94.655 97.0039 39.9991

157 MAFD 235307 391.968 -300.033 97.0046 39.9973

158 MCES 235415 471.737 -143.942 97.0056 39.9987
OG&E A-10 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

159 MILL 235594 309.516 -311.398 97.0037 39.9972

160 MTGV 235834 426.937 -310.43 97.0050 39.9972

161 NVAD 235987 243.915 -272.715 97.0029 39.9975

162 OZRK 236460 349.133 -390.626 97.0041 39.9965

163 PDTD 236777 334.055 -265.018 97.0039 39.9976

164 POTO 236826 572.215 -251.455 97.0068 39.9977

165 ROLL 237263 484.503 -253.958 97.0057 39.9977

166 ROSE 237300 500.59 -175.393 97.0059 39.9984

167 SALE 237506 498.94 -274.122 97.0059 39.9975

168 SENE 237656 233.959 -383.703 97.0028 39.9965

169 SPRC 237967 238.112 -373.616 97.0028 39.9966

170 SPVL 237976 332.385 -309.374 97.0039 39.9972

171 STEE 238043 503.354 -205.135 97.0059 39.9981

172 STOK 238082 310.911 -279.239 97.0037 39.9975

173 SWSP 238223 324.053 -150.325 97.0038 39.9986

174 TRKD 238252 340.418 -395.428 97.0040 39.9964

175 TRUM 238466 326.883 -197.796 97.0039 39.9982

176 UNIT 238524 238.567 -154.494 97.0028 39.9986

177 VIBU 238609 519.633 -267.258 97.0061 39.9976

178 VIEN 238620 470.383 -193.872 97.0056 39.9983

179 WAPP 238700 606.68 -358.746 97.0072 39.9968

180 WASG 238746 556.425 -164.993 97.0066 39.9985

181 WEST 238880 489.373 -377.809 97.0058 39.9966

182 ALBU 290234 -869.46 -501.713 96.9897 39.9955

183 ARTE 290600 -689.529 -773.897 96.9919 39.9930

184 AUGU 290640 -973.07 -598.391 96.9885 39.9946

185 CARL 291469 -680.335 -811.474 96.9920 39.9927

186 CARR 291515 -819.836 -665.132 96.9903 39.9940

187 CLAY 291887 -547.124 -374.102 96.9935 39.9966

188 CLOV 291939 -566.973 -599.296 96.9933 39.9946

189 CUBA 292241 -890.304 -392.495 96.9895 39.9965

190 CUBE 292250 -951.142 -489.293 96.9888 39.9956

191 DEMI 292436 -1007.99 -799.087 96.9881 39.9928

192 DURA 292665 -767.148 -577.618 96.9909 39.9948

193 EANT 292700 -735.089 -366.94 96.9913 39.9967

194 LAVG 294862 -738.245 -461.163 96.9913 39.9958

195 PROG 297094 -811.39 -578.971 96.9904 39.9948

196 RAMO 297254 -733.737 -615.175 96.9913 39.9944

197 ROSW 297610 -698.544 -712.921 96.9918 39.9936

198 ROY 297638 -644.735 -422.422 96.9924 39.9962
OG&E A-11 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

199 SANT 298085 -807.375 -445.708 96.9905 39.9960

200 SPRI 298501 -676.681 -374.272 96.9920 39.9966

201 STAY 298518 -810.491 -495.501 96.9904 39.9955

202 TNMN 299031 -912.488 -413.425 96.9892 39.9963

203 TUCU 299156 -604.359 -508.834 96.9929 39.9954

204 WAST 299569 -638.605 -820.288 96.9925 39.9926

205 WISD 299686 -856.967 -756.366 96.9899 39.9932

206 AIRS 340179 -212.731 -597.062 96.9975 39.9946

207 ARDM 340292 -12.242 -645.633 96.9999 39.9942

208 BENG 340670 174.368 -568.011 97.0021 39.9949

209 CANE 341437 71.857 -637.935 97.0009 39.9942

210 CHRT 341544 203.233 -632.067 97.0024 39.9943

211 CHAN 341684 10.494 -475.655 97.0001 39.9957

212 CHIK 341750 -83.175 -547.26 96.9990 39.9951

213 CCTY 342334 -165 -479.536 96.9981 39.9957

214 DUNC 342654 -88.38 -610.04 96.9990 39.9945

215 ELKC 342849 -216.769 -507.879 96.9974 39.9954

216 FORT 343281 -129.964 -541.113 96.9985 39.9951

217 GEAR 343497 -118.53 -482.187 96.9986 39.9956

218 HENN 344052 -31.964 -601.206 96.9996 39.9946

219 HOBA 344202 -189.062 -547.36 96.9978 39.9951

220 KING 344865 24.538 -664.103 97.0003 39.9940

221 LKEU 344975 141.702 -520.6 97.0017 39.9953

222 LEHI 345108 71.634 -612.05 97.0009 39.9945

223 MACI 345463 -254.63 -466.154 96.9970 39.9958

224 MALL 345589 -55.127 -425.644 96.9994 39.9962

225 MAYF 345648 -258.49 -512.583 96.9970 39.9954

226 MUSK 346130 149.764 -466.905 97.0018 39.9958

227 NOWA 346485 121.551 -364.038 97.0014 39.9967

228 OKAR 346620 -88.424 -473.338 96.9990 39.9957

229 OKEM 346638 63.188 -504.958 97.0008 39.9954

230 OKLA 346661 -54.198 -510.562 96.9994 39.9954

231 PAOL 346859 -23.665 -573.142 96.9997 39.9948

232 PAWH 346935 57.704 -369.174 97.0007 39.9967

233 PAWN 346944 16.927 -398.139 97.0002 39.9964

234 PONC 347196 -8.871 -363.068 96.9999 39.9967

235 PRYO 347309 150.763 -407.824 97.0018 39.9963

236 SHAT 348101 -256.963 -407.368 96.9970 39.9963

237 STIG 348497 171.02 -523.736 97.0020 39.9953

238 TULS 348992 99.361 -419.873 97.0012 39.9962
OG&E A-12 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

239 TUSK 349023 156.629 -592.395 97.0019 39.9946

240 WMWR 349629 -156.42 -581.308 96.9982 39.9947

241 WOLF 349748 30.212 -538.388 97.0004 39.9951

242 BOLI 400876 760.886 -500.256 97.0090 39.9955

243 BROW 401150 710.048 -480.346 97.0084 39.9957

244 CETR 401587 877.35 -456.294 97.0104 39.9959

245 DICS 402489 872.14 -391.132 97.0103 39.9965

246 DYER 402680 695.792 -409.316 97.0082 39.9963

247 GRNF 403697 760.795 -395.69 97.0090 39.9964

248 JSNN 404561 765.932 -476.414 97.0090 39.9957

249 LWER 405089 885.291 -487.757 97.0105 39.9956

250 LEXI 405210 790.003 -471.897 97.0093 39.9957

251 MASO 405720 694.163 -496.166 97.0082 39.9955

252 MEMP 405954 671.8 -522.492 97.0079 39.9953

253 MWFO 405956 681.292 -516.15 97.0080 39.9953

254 MUNF 406358 678.65 -495.241 97.0080 39.9955

255 SAMB 408065 697.077 -382.536 97.0082 39.9965

256 SAVA 408108 800.788 -498.682 97.0095 39.9955

257 UNCY 409219 711.595 -384.605 97.0084 39.9965

258 ABIL 410016 -251.753 -836.027 96.9970 39.9924

259 AMAR 410211 -425.302 -517.839 96.9950 39.9953

260 AUST 410428 -67.587 -1075.97 96.9992 39.9903

261 BRWN 411136 -43.861 -1571.39 96.9995 39.9858

262 COST 411889 60.611 -1044.72 97.0007 39.9906

263 COCR 412015 -51.832 -1360.01 96.9994 39.9877

264 CROS 412131 -204.599 -868.469 96.9976 39.9922

265 DFWT 412242 -1.867 -786.341 97.0000 39.9929

266 EAST 412715 -171.024 -840.253 96.9980 39.9924

267 ELPA 412797 -886.583 -860.763 96.9895 39.9922

268 HICO 414137 -97.323 -888.181 96.9989 39.9920

269 HUST 414300 157.976 -1108.38 97.0019 39.9900

270 KRES 414880 -434.746 -611.717 96.9949 39.9945

271 LKCK 414975 99.734 -693.521 97.0012 39.9937

272 LNGV 415348 220.962 -844.674 97.0026 39.9924

273 LUFK 415424 214.652 -969.69 97.0025 39.9912

274 MATH 415661 -86.438 -1330.47 96.9990 39.9880

275 MIDR 415890 -489.385 -878.123 96.9942 39.9921

276 MTLK 416104 -672.024 -1008.98 96.9921 39.9909

277 NACO 416177 223.065 -925.966 97.0026 39.9916

278 NAVA 416210 28.358 -892.028 97.0003 39.9919
OG&E A-13 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

279 NEWB 416270 239.111 -721.818 97.0028 39.9935

280 BPAT 417174 288.962 -1110.65 97.0034 39.9900

281 RANK 417431 -472.048 -959.488 96.9944 39.9913

282 SAAG 417943 -333.338 -952.54 96.9961 39.9914

283 SAAT 417945 -143.322 -1161.27 96.9983 39.9895

284 SHEF 418252 -463.759 -1019.19 96.9945 39.9908

285 STEP 418623 -112.988 -857.918 96.9987 39.9922

286 STER 418630 -376.683 -897.195 96.9956 39.9919

287 VALE 419270 -720.749 -1015.17 96.9915 39.9908

288 VICT 419364 6.882 -1236.45 97.0001 39.9888

289 WACO 419419 -21.834 -928.823 96.9997 39.9916

290 WATR 419499 -353.767 -916.015 96.9958 39.9917

291 WHEE 419665 57.489 -1008.99 97.0007 39.9909

292 WPDM 419916 262.792 -737.786 97.0031 39.9933

293 DORA 232302 433.256 -378.797 97.0051 39.9966

294 DIXN 112353 756.057 -267.193 97.0089 39.9976

295 DAUP 12172 864.408 -1050.41 97.0102 39.9905

296 FREV 123104 847.031 -117.884 97.0100 39.9989

297 WARR 18673 890.447 -788.703 97.0105 39.9929

298 MDTN 235562 493.264 -87.222 97.0058 39.9992
OG&E A-14 Trinity Consultants

CALMET Processing Protocol 083701.0004

TABLE A-4. LIST OF OVER WATER METEOROLOGICAL STATIONS

Number

Station 

ID

Input file 

Name

LCC 

East 

(km)

LCC North

(km) Long Lat

1 42001 42001 746.874 -1541.35 89.67 25.9

2 42002 42002 265.486 -1650.616 94.42 25.19

3 42007 42007 795.674 -1063.667 88.77 30.09

4 42019 42019 163.178 -1342.917 95.36 27.91

5 42020 42020 30.212 -1453.738 96.7 26.94

6 42035 42035 254.465 -1193.539 94.41 29.25

7 42040 42040 859.497 -1160.066 88.21 29.18

8 BURL1 42045 743.116 -1202.117 89.43 28.9

9 DPIA1 42046 861.385 -1039.466 88.07 30.25

10 GDIL1 42047 687.984 -1164.910 89.96 29.27

11 PTAT2 42048 -4.980 -1353.398 97.05 27.83

12 SRST2 42049 288.163 -1175.682 94.05 29.67
Entergy Trinity Consultants

BART Analysis – White Bluff

APPENDIX D

CEMS DATA FROM CAMD FOR 2001 TO 2003 AND 2009 TO 2011
 Unit ID Date

 SO2

(tons)

 Heat Input 

(MMBtu)

1 1/5/2001 1.427 26,054 1 1/6/2001 42.883 149,330 1 1/7/2001 68.245 194,455 1 1/8/2001 63.914 182,770 1 1/9/2001 67.859 204,772 1 1/10/2001 65.955 190,485 1 1/11/2001 70.031 202,920 1 1/12/2001 56.743 187,273 1 1/13/2001 64.013 207,805 1 1/14/2001 48.542 144,623 1 1/15/2001 67.075 192,264 1 1/16/2001 57.886 185,487 1 1/17/2001 68.777 198,849 1 1/18/2001 62.858 188,091 1 1/19/2001 58.119 185,976 1 1/20/2001 66.6 191,109 1 1/21/2001 69.856 206,742 1 1/22/2001 65.144 190,490 1 1/23/2001 64.994 194,193 1 1/24/2001 56.804 182,694 1 1/25/2001 63.27 202,127 1 1/26/2001 55.296 171,617 1 4/3/2001 0.547 6,873 1 4/4/2001 1.055 8,573 1 4/5/2001 1.546 10,088 1 4/6/2001 8.967 38,007 1 4/7/2001 6.478 26,784 1 4/9/2001 5.976 26,103 1 4/10/2001 24.207 93,161 1 4/11/2001 55.76 174,874 1 4/12/2001 59.522 173,490 1 4/13/2001 54.427 165,840 1 4/14/2001 58.422 171,216 1 4/15/2001 24.188 72,680 1 4/16/2001 2.533 10,525 1 4/17/2001 56.651 164,701 1 4/18/2001 64.409 164,695 1 4/19/2001 61.953 160,949 1 4/20/2001 63.59 173,481 1 4/21/2001 31.694 94,929 1 4/22/2001 59.626 164,679 1 4/23/2001 43.525 120,867 1 4/24/2001 9.105 28,862 1 4/25/2001 62.678 180,855 1 4/26/2001 49.349 140,127
1 4/27/2001 62.261 187,109 1 4/28/2001 62.59 179,852 1 4/29/2001 52.9 155,338 1 4/30/2001 69.128 180,489 1 5/1/2001 49.114 136,478 1 5/2/2001 63.29 182,498 1 5/3/2001 62.078 184,546 1 5/4/2001 63.607 185,637 1 5/5/2001 60.206 174,287 1 5/6/2001 55.887 164,969 1 5/7/2001 66.414 181,665 1 5/8/2001 66.104 187,835 1 5/9/2001 61.648 183,461 1 5/10/2001 61.171 181,272 1 5/11/2001 57.942 172,097 1 5/12/2001 5.656 17,561 1 5/13/2001 0.609 3,950 1 5/14/2001 55.397 159,810 1 5/15/2001 64.475 183,212 1 5/16/2001 63.77 181,857 1 5/17/2001 59.676 176,776 1 5/18/2001 61.378 176,568 1 5/19/2001 64.114 180,838 1 5/20/2001 59.087 170,626 1 5/21/2001 50.906 148,628 1 5/22/2001 52.519 154,556 1 5/23/2001 58.172 170,287 1 5/24/2001 61.455 179,175 1 5/25/2001 58.992 169,017 1 5/26/2001 60.789 175,004 1 5/27/2001 58.749 172,696 1 5/28/2001 64.869 174,922 1 5/29/2001 60.546 180,550 1 5/30/2001 59.685 173,119 1 5/31/2001 55.194 161,952 1 6/1/2001 56.076 161,968 1 6/2/2001 62.356 179,767 1 6/3/2001 62.691 187,445 1 6/4/2001 69.826 195,288 1 6/5/2001 65.276 187,650 1 6/6/2001 62.966 184,410 1 6/7/2001 62.048 178,041 1 6/8/2001 70.887 192,530 1 6/9/2001 59.876 178,409 1 6/10/2001 58.98 177,831 1 6/11/2001 61.296 185,722 1 6/12/2001 68.818 196,712
1 6/13/2001 72.77 206,791 1 6/14/2001 82.035 228,623 1 6/15/2001 72.149 202,380 1 6/16/2001 69.886 199,793 1 6/17/2001 71.396 201,210 1 6/18/2001 75.678 217,184 1 6/19/2001 69.793 203,565 1 6/20/2001 70.83 204,866 1 6/21/2001 69.739 203,174 1 6/22/2001 69.941 208,054 1 6/23/2001 67.056 193,075 1 6/24/2001 66.104 193,681 1 6/25/2001 62.686 186,522 1 6/26/2001 68.046 197,197 1 6/27/2001 59.758 173,545 1 6/28/2001 69.789 201,036 1 6/29/2001 71.015 199,606 1 6/30/2001 67.63 196,607 1 7/1/2001 64.938 190,313 1 7/2/2001 67.968 201,234 1 7/3/2001 74.092 198,062 1 7/4/2001 68.436 197,642 1 7/5/2001 67.987 196,138 1 7/6/2001 65.934 200,553 1 7/7/2001 67.562 194,432 1 7/8/2001 61.583 219,889 1 7/9/2001 59.883 204,470 1 7/10/2001 83.794 215,984 1 7/11/2001 67.369 194,599 1 7/12/2001 64.477 189,174 1 7/13/2001 7.831 34,051 1 7/14/2001 68.11 194,471 1 7/15/2001 69.282 181,728 1 7/16/2001 70.182 195,428 1 7/17/2001 56.916 200,084 1 7/18/2001 67.033 211,803 1 7/19/2001 67.091 201,315 1 7/20/2001 79.587 213,335 1 7/21/2001 67.74 202,185 1 7/22/2001 70.121 207,400 1 7/23/2001 58.683 178,725 1 7/24/2001 57.098 206,917 1 7/25/2001 52.214 177,632 1 7/26/2001 70.82 217,541 1 7/27/2001 68.711 199,604 1 7/28/2001 69.585 206,823 1 7/29/2001 49.378 192,050
1 7/30/2001 54.797 208,774 1 7/31/2001 69.394 201,992 1 8/1/2001 63.745 189,763 1 8/2/2001 71.075 218,726 1 8/3/2001 69.396 200,818 1 8/4/2001 64.49 197,670 1 8/5/2001 64.868 191,622 1 8/6/2001 63.636 212,620 1 8/7/2001 57.665 191,653 1 8/8/2001 64.678 213,642 1 8/9/2001 47.023 193,280 1 8/10/2001 58.4 208,250 1 8/11/2001 48.012 184,435 1 8/12/2001 60.14 189,596 1 8/13/2001 57.645 181,656 1 8/14/2001 58.304 186,898 1 8/15/2001 58.225 180,890 1 8/16/2001 71.981 214,532 1 8/17/2001 64.94 198,444 1 8/18/2001 67.218 203,643 1 8/19/2001 67.619 192,562 1 8/20/2001 65.533 194,140 1 8/21/2001 62.648 196,979 1 8/22/2001 68.512 199,137 1 8/23/2001 70.948 209,984 1 8/24/2001 63.321 194,695 1 8/25/2001 59.971 192,155 1 8/26/2001 62.562 189,841 1 8/27/2001 67.055 195,409 1 8/28/2001 63.287 190,177 1 8/29/2001 69.2 199,246 1 8/30/2001 61.391 189,474 1 8/31/2001 65.847 203,921 1 9/1/2001 60.489 185,501 1 9/2/2001 57.116 170,413 1 9/3/2001 55.47 188,460 1 9/4/2001 52.537 205,793 1 9/5/2001 69.889 198,384 1 9/6/2001 68.654 207,117 1 9/7/2001 62.387 187,751 1 9/8/2001 69.789 198,880 1 9/9/2001 58.532 171,631 1 9/10/2001 51.286 186,885 1 9/11/2001 58.135 183,969 1 9/12/2001 64.083 193,770 1 9/13/2001 66.92 207,704 1 9/14/2001 65.662 199,431
1 9/15/2001 47.991 149,423 1 9/16/2001 61.057 173,907 1 9/17/2001 64.579 196,262 1 9/18/2001 66.304 197,588 1 9/19/2001 42.479 135,150 1 9/20/2001 59.628 188,047 1 9/21/2001 55.154 191,343 1 9/22/2001 59.266 203,172 1 9/23/2001 52.687 178,601 1 9/24/2001 61.1 191,425 1 9/25/2001 58.935 173,197 1 9/26/2001 58.448 172,509 1 9/27/2001 64.197 190,973 1 9/28/2001 59.903 183,833 1 9/29/2001 52.612 164,330 1 9/30/2001 47.5 151,261 1 10/1/2001 55.079 172,521 1 10/2/2001 48.89 185,647 1 10/3/2001 55.909 193,065 1 10/4/2001 61.833 206,607 1 10/8/2001 36.186 112,976 1 10/9/2001 72.988 220,068 1 10/10/2001 66.767 206,153 1 10/11/2001 66.98 219,629 1 10/12/2001 59.135 188,092 1 10/13/2001 62.573 194,097 1 10/14/2001 51.93 161,238 1 10/15/2001 61.904 193,931 1 10/16/2001 62.534 190,118 1 10/17/2001 62.392 191,378 1 10/18/2001 55.951 175,127 1 10/19/2001 43.663 140,910 1 10/21/2001 0.262 8,330 1 10/22/2001 35.667 126,447 1 10/23/2001 25.149 78,862 1 10/24/2001 12.77 50,607 1 10/25/2001 66.722 207,816 1 10/26/2001 62.93 193,711 1 10/27/2001 59.814 193,744 1 10/28/2001 67.952 212,723 1 10/29/2001 62.573 196,544 1 10/30/2001 68.954 213,301 1 10/31/2001 61.194 189,622 1 11/1/2001 63.85 199,791 1 11/2/2001 62.444 192,209 1 11/3/2001 67.009 174,125 1 11/4/2001 54.729 170,634
1 11/5/2001 63.401 199,959 1 11/6/2001 66.746 205,470 1 11/7/2001 49.409 157,872 1 11/8/2001 69.802 213,781 1 11/9/2001 64.883 203,484 1 11/10/2001 73.337 218,963 1 11/11/2001 61.848 187,807 1 11/12/2001 65.828 204,133 1 11/13/2001 63.046 189,526 1 11/14/2001 22.495 92,696 1 11/15/2001 36.48 111,862 1 11/16/2001 36.041 114,142 1 11/17/2001 35.271 115,121 1 11/18/2001 32.37 105,190 1 11/21/2001 0.361 9,218 1 11/22/2001 28.09 104,413 1 11/23/2001 45.663 142,873 1 11/24/2001 48.864 149,650 1 11/25/2001 47.17 157,334 1 11/26/2001 60.874 188,092 1 11/27/2001 66.46 203,520 1 11/28/2001 63.65 198,498 1 11/29/2001 71.885 218,758 1 11/30/2001 66.244 185,155 1 12/1/2001 64.506 193,567 1 12/2/2001 45.619 139,533 1 12/3/2001 59.412 195,898 1 12/4/2001 67.238 203,423 1 12/5/2001 65.347 196,961 1 12/6/2001 66.744 199,382 1 12/7/2001 65.415 190,727 1 12/8/2001 58.997 188,729 1 12/9/2001 57.892 180,602 1 12/10/2001 71.695 204,009 1 12/11/2001 71.263 198,053 1 12/12/2001 65.161 194,984 1 12/13/2001 64.638 191,787 1 12/14/2001 62.025 189,609 1 12/15/2001 55.166 191,899 1 12/16/2001 60.591 193,126 1 12/17/2001 58.482 185,205 1 12/18/2001 64.737 197,302 1 12/19/2001 61.156 186,406 1 12/20/2001 68.073 202,192 1 12/21/2001 57.529 181,524 1 12/22/2001 58.981 185,305 1 12/23/2001 51.357 174,111
1 12/24/2001 59.022 184,946 1 12/25/2001 50.786 161,430 1 12/26/2001 66.38 205,423 1 12/27/2001 64.214 194,709 1 12/28/2001 64.287 192,369 1 12/29/2001 61.542 192,964 1 12/30/2001 65.491 212,269 1 12/31/2001 47.421 191,796 1 1/1/2002 63.679 210,165 1 1/2/2002 63.43 201,368 1 1/3/2002 67.6 206,525 1 1/4/2002 65.712 198,917 1 1/5/2002 61.49 190,678 1 1/6/2002 64.831 200,976 1 1/7/2002 62.917 197,310 1 1/8/2002 54.84 171,604 1 1/9/2002 53.326 171,734 1 1/10/2002 63.441 195,374 1 1/11/2002 62.568 188,959 1 1/12/2002 68.436 202,097 1 1/13/2002 63.656 186,189 1 1/14/2002 74.083 201,801 1 1/15/2002 66.62 197,855 1 1/16/2002 73.726 214,133 1 1/17/2002 64.49 192,439 1 1/18/2002 69.301 208,951 1 1/19/2002 25.979 77,912 1 1/21/2002 0.188 3,231 1 1/22/2002 55.559 176,106 1 1/23/2002 62.193 190,325 1 1/24/2002 50.749 160,297 1 1/25/2002 61.775 193,282 1 1/26/2002 61.535 197,676 1 1/27/2002 56.132 180,536 1 1/28/2002 64.414 181,611 1 1/29/2002 64.231 189,953 1 1/30/2002 64.22 198,999 1 1/31/2002 66.106 192,014 1 2/1/2002 69.319 210,093 1 2/2/2002 59.419 178,351 1 2/3/2002 65.519 198,493 1 2/4/2002 65.006 198,991 1 2/5/2002 70.877 210,678 1 2/6/2002 61.769 188,285 1 2/7/2002 67.84 204,820 1 2/8/2002 59.141 180,179 1 2/9/2002 66.066 207,388
1 2/10/2002 59.946 180,151 1 2/11/2002 69.365 209,221 1 2/12/2002 61.579 192,686 1 2/13/2002 67.463 207,532 1 2/14/2002 41.55 154,075 1 2/16/2002 18.353 67,944 1 2/17/2002 64.472 203,175 1 2/18/2002 56.369 184,089 1 2/19/2002 67.73 206,560 1 2/20/2002 59.191 191,606 1 2/21/2002 74.264 224,126 1 2/22/2002 54.91 198,622 1 2/23/2002 52.745 219,630 1 2/24/2002 49.357 179,837 1 2/25/2002 70.098 204,152 1 2/26/2002 53.344 194,187 1 2/27/2002 64.448 206,536 1 2/28/2002 58.543 184,634 1 3/1/2002 68.764 218,362 1 3/2/2002 60.402 190,520 1 3/3/2002 68.446 209,229 1 3/4/2002 62.583 191,590 1 3/5/2002 70.861 214,707 1 3/6/2002 64.212 203,299 1 3/7/2002 70.486 214,514 1 3/8/2002 61.141 186,812 1 4/13/2002 5.708 20,969 1 4/14/2002 34.795 106,854 1 4/15/2002 57.024 166,491 1 4/16/2002 53.047 171,720 1 4/17/2002 53.468 175,834 1 4/18/2002 43.8 166,016 1 4/19/2002 48.83 175,977 1 4/20/2002 8.323 28,418 1 4/21/2002 0.003 580 1 4/22/2002 38.239 113,983 1 4/23/2002 68.634 190,260 1 4/24/2002 63.012 191,729 1 4/25/2002 63.787 197,983 1 4/26/2002 59.158 185,084 1 4/27/2002 69.829 199,244 1 4/28/2002 69.214 186,436 1 4/29/2002 70.324 197,582 1 4/30/2002 65.809 191,490 1 5/1/2002 73.078 189,345 1 5/2/2002 62.135 174,389 1 5/3/2002 65.047 185,059
1 5/4/2002 61.545 174,429 1 5/5/2002 63.546 183,352 1 5/6/2002 61.198 179,430 1 5/7/2002 69.438 188,297 1 5/8/2002 62.149 169,536 1 5/9/2002 66.113 182,139 1 5/10/2002 38.24 144,931 1 5/11/2002 35.014 116,084 1 5/12/2002 54.48 161,097 1 5/13/2002 62.067 170,670 1 5/14/2002 55.953 165,617 1 5/15/2002 67.13 216,015 1 5/16/2002 61.757 191,148 1 5/19/2002 19.888 74,291 1 5/20/2002 58.383 158,571 1 5/21/2002 58.11 160,272 1 5/22/2002 64.735 186,565 1 5/23/2002 58.363 168,141 1 5/24/2002 68 192,062 1 5/25/2002 65.193 184,983 1 5/26/2002 65.7 186,889 1 5/27/2002 68.492 186,964 1 5/28/2002 68.606 180,790 1 5/29/2002 66.227 185,455 1 5/30/2002 68.742 196,710 1 5/31/2002 64.839 187,781 1 6/1/2002 69.158 192,581 1 6/2/2002 65.068 183,215 1 6/3/2002 77.57 200,837 1 6/4/2002 70.507 189,222 1 6/5/2002 78.176 213,694 1 6/6/2002 67.509 192,390 1 6/7/2002 67.76 201,030 1 6/8/2002 65.933 190,291 1 6/9/2002 66.485 191,411 1 6/10/2002 66.865 194,536 1 6/11/2002 71.58 208,004 1 6/12/2002 65.373 188,944 1 6/13/2002 75.211 208,049 1 6/14/2002 60.856 173,253 1 6/15/2002 64.898 184,036 1 6/16/2002 56.896 167,608 1 6/17/2002 63.565 188,633 1 6/18/2002 63.102 186,073 1 6/19/2002 79.317 195,493 1 6/20/2002 79.393 189,472 1 6/21/2002 73.805 197,863
1 6/22/2002 49.797 143,284 1 6/23/2002 75.952 210,428 1 6/24/2002 68.298 191,123 1 6/25/2002 78.177 203,120 1 6/26/2002 71.694 188,443 1 6/27/2002 69.505 183,540 1 6/28/2002 65.062 185,336 1 6/29/2002 68.421 186,719 1 6/30/2002 71.327 193,656 1 7/1/2002 79.947 217,232 1 7/2/2002 70.741 198,667 1 7/3/2002 67.705 216,727 1 7/4/2002 66.951 188,922 1 7/5/2002 64.28 199,855 1 7/6/2002 54.728 192,169 1 7/7/2002 56.335 188,886 1 7/8/2002 59.271 194,915 1 7/9/2002 74.651 209,347 1 7/10/2002 67.581 184,702 1 7/11/2002 68.305 182,884 1 7/12/2002 68.551 187,138 1 7/13/2002 76.388 208,472 1 7/14/2002 70.828 197,928 1 7/15/2002 69.823 211,579 1 7/16/2002 63.73 193,356 1 7/17/2002 67.856 189,957 1 7/18/2002 72.426 186,966 1 7/19/2002 73.675 189,888 1 7/20/2002 69.983 185,830 1 7/21/2002 76.773 205,421 1 7/22/2002 68.664 191,286 1 7/23/2002 72.324 195,212 1 7/24/2002 76.622 210,335 1 7/25/2002 66.019 189,454 1 7/26/2002 79.278 206,613 1 7/27/2002 69.296 195,490 1 7/28/2002 69.506 215,790 1 7/29/2002 63.288 189,536 1 7/30/2002 31.158 89,903 1 7/31/2002 0.119 11,078 1 8/1/2002 52.278 165,075 1 8/2/2002 71.323 205,542 1 8/3/2002 66.838 191,490 1 8/4/2002 75.336 211,226 1 8/5/2002 64.167 182,521 1 8/6/2002 75.767 208,980 1 8/7/2002 69.578 193,962
1 8/8/2002 73.682 199,447 1 8/9/2002 67.065 191,470 1 8/10/2002 65.249 177,073 1 8/11/2002 57.964 156,967 1 8/12/2002 62.398 172,804 1 8/13/2002 68.958 187,693 1 8/14/2002 73.119 205,366 1 8/15/2002 70.911 202,259 1 8/16/2002 61.045 187,020 1 8/17/2002 75.284 205,494 1 8/18/2002 60.227 182,750 1 8/19/2002 70.463 212,434 1 8/20/2002 66.725 195,101 1 8/21/2002 72.13 214,663 1 8/22/2002 66.974 195,545 1 8/23/2002 71.867 216,637 1 8/24/2002 63.142 187,508 1 8/25/2002 70.874 202,602 1 8/26/2002 67.41 189,884 1 8/27/2002 69.688 196,659 1 8/28/2002 63.118 181,584 1 8/29/2002 72.557 207,110 1 8/30/2002 66.942 189,760 1 8/31/2002 75.762 205,778 1 9/1/2002 55.924 185,580 1 9/2/2002 67.586 197,260 1 9/3/2002 70.147 191,949 1 9/4/2002 83.826 203,721 1 9/5/2002 69.924 187,708 1 9/6/2002 73.166 205,867 1 9/7/2002 69.284 188,362 1 9/8/2002 69.52 193,741 1 9/9/2002 62.599 188,709 1 9/10/2002 73.98 210,022 1 9/11/2002 68.141 190,295 1 9/12/2002 66.791 204,978 1 9/13/2002 63.838 182,704 1 9/14/2002 73.45 210,815 1 9/15/2002 63.503 193,497 1 9/16/2002 69.72 214,873 1 9/17/2002 62.437 191,286 1 9/18/2002 73.106 215,255 1 9/19/2002 69.606 200,089 1 9/20/2002 70.428 212,169 1 9/21/2002 63.715 187,640 1 9/22/2002 69.43 197,599 1 9/23/2002 62.004 182,589
1 9/24/2002 64.476 183,324 1 9/25/2002 57.247 162,246 1 9/26/2002 59.154 177,372 1 9/27/2002 62.503 181,676 1 9/28/2002 77.516 198,966 1 9/29/2002 68.433 180,931 1 9/30/2002 71.244 201,058 1 10/1/2002 64.037 177,954 1 10/2/2002 72.814 198,480 1 10/3/2002 68.824 180,764 1 10/4/2002 74.934 200,236 1 10/5/2002 66.208 182,168 1 10/6/2002 65.293 206,104 1 10/7/2002 57.704 184,131 1 10/8/2002 70.366 165,991 1 10/9/2002 68.841 174,546 1 10/10/2002 72.823 205,605 1 10/11/2002 62.789 196,835 1 10/12/2002 67.896 219,518 1 10/13/2002 64.469 192,609 1 10/14/2002 76.585 209,355 1 10/15/2002 61.276 184,644 1 10/16/2002 63.876 190,268 1 10/17/2002 63.739 178,031 1 10/18/2002 71.555 196,906 1 10/19/2002 65.951 179,201 1 10/20/2002 69.229 184,225 1 10/21/2002 67.223 172,452 1 10/22/2002 68.757 200,912 1 10/23/2002 66.493 181,742 1 10/24/2002 77.876 197,936 1 10/25/2002 66.975 188,079 1 10/26/2002 72.399 203,780 1 10/27/2002 23.99 74,983 1 10/28/2002 54.183 149,783 1 10/29/2002 62.737 145,898 1 10/30/2002 50.869 128,978 1 10/31/2002 70.349 186,719 1 11/1/2002 67.923 185,442 1 11/2/2002 59.053 158,260 1 11/3/2002 63.912 177,005 1 11/4/2002 67.24 179,065 1 11/5/2002 74.584 200,208 1 11/6/2002 59.928 179,634 1 11/7/2002 72.689 196,407 1 11/8/2002 67.716 178,329 1 11/9/2002 77.283 191,726
1 11/10/2002 63.848 171,424 1 11/11/2002 72.94 193,090 1 11/12/2002 61.283 167,255 1 11/13/2002 69.047 188,017 1 11/14/2002 65.669 178,330 1 11/15/2002 73.693 194,656 1 11/16/2002 66.131 172,077 1 11/17/2002 69.205 194,371 1 11/18/2002 63.507 172,577 1 11/19/2002 71.279 187,306 1 11/20/2002 57.233 149,545 1 11/22/2002 0.285 2,467 1 11/23/2002 43.397 119,570 1 11/24/2002 70.071 193,889 1 11/25/2002 65.963 178,921 1 11/26/2002 65.652 192,450 1 11/27/2002 70.457 162,879 1 11/28/2002 64.064 161,891 1 11/29/2002 46.986 123,508 1 11/30/2002 64.959 169,536 1 12/1/2002 66.605 169,543 1 12/2/2002 73.74 192,490 1 12/3/2002 70.465 178,915 1 12/4/2002 76.84 197,882 1 12/5/2002 66.449 167,574 1 12/6/2002 72.172 176,674 1 12/7/2002 62.203 168,865 1 12/8/2002 65.528 190,748 1 12/9/2002 61.204 179,392 1 12/10/2002 73.699 186,035 1 12/11/2002 67.461 170,849 1 12/12/2002 75.376 194,554 1 12/13/2002 59.989 153,460 1 12/14/2002 68.99 177,279 1 12/15/2002 68.305 160,456 1 12/16/2002 76.191 180,966 1 12/17/2002 73.332 173,618 1 12/18/2002 76.888 195,180 1 12/19/2002 71.893 176,889 1 12/20/2002 67.569 170,932 1 12/21/2002 62.678 166,491 1 12/22/2002 70.113 179,450 1 12/23/2002 71.766 183,176 1 12/24/2002 70.094 183,058 1 12/25/2002 68.993 179,073 1 12/26/2002 72.084 190,734 1 12/27/2002 66.248 171,995
1 12/28/2002 71.41 188,655 1 12/29/2002 60.327 170,084 1 12/30/2002 60.528 169,080 1 12/31/2002 54.642 149,739 1 1/1/2003 73.915 190,490 1 1/2/2003 78.753 194,372 1 1/3/2003 64.163 174,996 1 1/4/2003 74.148 202,634 1 1/5/2003 66.118 176,220 1 1/6/2003 73.507 201,538 1 1/7/2003 61.691 170,119 1 1/8/2003 53.155 190,141 1 1/9/2003 51.59 150,755 1 1/10/2003 54.815 148,813 1 1/11/2003 67.307 178,120 1 1/12/2003 79.089 196,635 1 1/13/2003 60.962 167,295 1 1/14/2003 63.486 199,432 1 1/15/2003 57.585 174,044 1 1/16/2003 62.495 194,099 1 1/17/2003 31.403 95,315 1 1/18/2003 65.728 183,717 1 1/19/2003 60.339 163,905 1 1/20/2003 61.16 165,939 1 1/21/2003 55.715 164,810 1 1/22/2003 59.21 182,170 1 1/23/2003 55.487 186,596 1 1/24/2003 62.545 198,856 1 1/25/2003 62.512 178,918 1 1/26/2003 66.7 191,266 1 1/27/2003 61.967 169,600 1 1/28/2003 67.579 195,026 1 1/29/2003 61.284 173,870 1 1/30/2003 61.872 198,309 1 1/31/2003 58.385 171,516 1 2/1/2003 75.945 197,489 1 2/2/2003 66.362 168,728 1 2/3/2003 65.998 184,364 1 2/4/2003 68.644 176,414 1 2/5/2003 90.467 196,322 1 2/6/2003 58.866 171,981 1 2/7/2003 78.827 199,612 1 2/8/2003 63.091 174,303 1 2/9/2003 63.7 187,172 1 2/10/2003 48.019 168,271 1 2/11/2003 55.823 169,313 1 2/12/2003 62.516 159,288
1 2/13/2003 61.421 174,121 1 2/14/2003 62.005 158,766 1 2/15/2003 78.969 200,801 1 2/16/2003 72.08 184,036 1 2/17/2003 69.689 202,163 1 2/18/2003 62.206 163,617 1 2/19/2003 68.896 180,477 1 2/20/2003 64.623 173,881 1 2/21/2003 67.163 183,845 1 2/22/2003 57.606 157,110 1 2/23/2003 69.672 192,959 1 2/24/2003 57.34 194,459 1 2/25/2003 55.535 183,066 1 2/26/2003 62.888 185,446 1 2/27/2003 47.595 156,992 1 2/28/2003 51.073 147,424 1 3/1/2003 40.516 108,627 1 3/2/2003 52.253 144,424 1 3/3/2003 48.089 173,987 1 3/4/2003 49.411 152,776 1 3/5/2003 48.333 158,937 1 3/6/2003 58.036 202,330 1 3/7/2003 46.863 145,062 1 3/8/2003 49.793 175,267 1 3/9/2003 70.656 170,559 1 3/10/2003 62.434 202,802 1 3/11/2003 57.399 184,481 1 3/12/2003 45.609 164,665 1 3/13/2003 37.658 145,800 1 3/14/2003 58.95 199,236 1 3/15/2003 61.202 187,834 1 3/16/2003 53.613 170,221 1 3/17/2003 59.39 175,018 1 3/18/2003 78.889 209,616 1 3/19/2003 71.377 186,412 1 3/20/2003 86.469 198,170 1 3/21/2003 75.59 185,082 1 3/22/2003 91.133 212,229 1 3/23/2003 89.95 183,040 1 3/24/2003 68.44 199,438 1 3/25/2003 66.328 167,699 1 3/26/2003 87.734 208,448 1 3/27/2003 62.384 171,469 1 4/1/2003 77.815 192,159 1 4/2/2003 75.176 180,236 1 4/3/2003 66.211 194,903 1 4/4/2003 36.75 175,240
1 4/5/2003 62.096 198,466 1 4/6/2003 68.474 174,682 1 4/7/2003 71.167 204,526 1 4/8/2003 73.012 203,697 1 4/9/2003 76.151 202,733 1 4/10/2003 68.052 175,982 1 4/11/2003 75.146 191,851 1 4/12/2003 70.72 186,941 1 4/13/2003 58.355 150,660 1 4/14/2003 69.968 192,204 1 4/15/2003 57.581 162,914 1 4/16/2003 68.308 187,283 1 4/17/2003 69.638 194,059 1 4/18/2003 47.058 137,341 1 4/19/2003 40.801 138,266 1 4/20/2003 69.525 184,518 1 4/21/2003 63.383 195,627 1 4/22/2003 46.951 156,554 1 4/23/2003 53.949 166,751 1 4/24/2003 57.137 173,637 1 4/25/2003 67.083 198,800 1 4/26/2003 65.889 178,524 1 4/27/2003 63.961 184,933 1 4/28/2003 56.091 164,029 1 5/14/2003 0.049 15,011 1 5/15/2003 15.377 77,551 1 5/16/2003 68.357 191,499 1 5/17/2003 64.285 195,408 1 5/18/2003 18.734 103,256 1 5/19/2003 31.395 95,092 1 5/20/2003 22.936 92,627 1 5/21/2003 28.402 89,420 1 5/22/2003 41.112 124,468 1 5/23/2003 59.486 174,644 1 5/24/2003 54.912 160,872 1 5/25/2003 56.33 165,561 1 5/26/2003 58.981 169,606 1 5/27/2003 63.996 182,690 1 5/28/2003 63.645 171,811 1 5/29/2003 60.784 184,084 1 5/30/2003 54.991 184,091 1 5/31/2003 75.624 209,565 1 6/1/2003 60.852 182,601 1 6/2/2003 63.49 206,040 1 6/3/2003 60.287 183,880 1 6/4/2003 67.308 202,062 1 6/5/2003 60.479 181,552
1 6/6/2003 55.256 192,138 1 6/7/2003 60.258 186,045 1 6/8/2003 65.11 194,271 1 6/9/2003 57.75 176,036 1 6/10/2003 62.436 203,259 1 6/11/2003 66.898 189,842 1 6/12/2003 70.574 207,990 1 6/13/2003 56.696 175,684 1 6/14/2003 71.951 215,265 1 6/15/2003 58.017 186,958 1 6/16/2003 59.332 195,251 1 6/17/2003 50.246 162,323 1 6/18/2003 72.322 208,449 1 6/19/2003 64.908 188,054 1 6/20/2003 67.928 206,650 1 6/21/2003 62.11 190,843 1 6/22/2003 66.638 201,823 1 6/23/2003 64.963 195,499 1 6/24/2003 68.687 206,961 1 6/25/2003 60.499 189,095 1 6/26/2003 72.145 210,390 1 6/27/2003 64.627 187,355 1 6/28/2003 67.706 208,435 1 6/29/2003 67.217 187,558 1 6/30/2003 65.28 203,057 1 7/1/2003 65.351 190,432 1 7/2/2003 69.546 199,595 1 7/3/2003 64.51 190,141 1 7/4/2003 69.444 199,252 1 7/5/2003 63.391 186,550 1 7/6/2003 68.122 194,179 1 7/7/2003 64.627 194,081 1 7/8/2003 70.035 216,937 1 7/9/2003 67.854 192,724 1 7/10/2003 75.468 212,229 1 7/11/2003 40.227 119,467 1 7/12/2003 43.857 177,807 1 7/13/2003 64.739 190,585 1 7/14/2003 75.933 214,321 1 7/15/2003 65.332 189,958 1 7/16/2003 79.905 210,593 1 7/17/2003 66.713 185,541 1 7/18/2003 74.769 200,491 1 7/19/2003 63.41 179,781 1 7/20/2003 64.059 187,000 1 7/21/2003 64.143 182,203 1 7/22/2003 69.373 208,488
1 7/23/2003 61.926 187,284 1 7/24/2003 65.816 188,519 1 7/25/2003 68.838 192,488 1 7/26/2003 75.838 208,652 1 7/27/2003 81.805 189,342 1 7/28/2003 77.288 202,758 1 7/29/2003 64.397 181,305 1 7/30/2003 74.549 207,311 1 7/31/2003 60.462 178,377 1 8/1/2003 79.776 207,621 1 8/2/2003 74.712 190,328 1 8/3/2003 73.136 185,354 1 8/4/2003 69.243 182,655 1 8/5/2003 74.251 202,146 1 8/6/2003 68.204 180,048 1 8/7/2003 81.741 211,571 1 8/8/2003 75.561 180,633 1 8/9/2003 86.654 208,892 1 8/10/2003 72.31 183,393 1 8/11/2003 74.953 181,523 1 8/12/2003 69.09 171,808 1 8/13/2003 86.837 203,211 1 8/14/2003 73.976 186,090 1 8/15/2003 73.209 203,578 1 8/16/2003 67.895 181,561 1 8/17/2003 93.162 196,475 1 8/18/2003 72.154 174,771 1 8/19/2003 74.077 193,269 1 8/20/2003 73.109 175,428 1 8/21/2003 77.381 201,428 1 8/22/2003 70.2 182,433 1 8/23/2003 91.532 202,832 1 8/24/2003 65.128 177,111 1 8/25/2003 73.702 201,739 1 8/26/2003 84.332 190,904 1 8/27/2003 79.137 210,683 1 8/28/2003 78.61 181,626 1 8/29/2003 86.346 205,609 1 8/30/2003 68.113 169,092 1 8/31/2003 60.59 164,527 1 9/1/2003 80.553 183,088 1 9/2/2003 66.713 192,087 1 9/3/2003 84.924 200,176 1 9/4/2003 82.67 203,396 1 9/5/2003 64.663 170,245 1 9/6/2003 71.003 180,289 1 9/7/2003 68.442 188,070
1 9/8/2003 72.396 200,412 1 9/9/2003 52.094 186,675 1 9/10/2003 51.619 204,556 1 9/11/2003 60.897 188,556 1 9/12/2003 77.23 215,322 1 9/13/2003 70.109 191,303 1 9/14/2003 67.612 198,122 1 9/15/2003 50.225 144,245 1 9/16/2003 61.598 186,390 1 9/17/2003 47.096 176,742 1 9/18/2003 73.404 201,265 1 9/19/2003 78.07 183,382 1 9/20/2003 67.711 190,857 1 9/21/2003 50.187 147,848 1 9/22/2003 72.89 209,098 1 9/23/2003 63.921 188,354 1 9/24/2003 72.307 209,389 1 9/25/2003 68.655 189,550 1 9/26/2003 74.139 217,294 1 9/27/2003 62.645 192,418 1 9/28/2003 65.072 196,056 1 9/29/2003 51.733 150,167 1 9/30/2003 75.945 179,170 1 10/1/2003 75.132 191,347 1 10/2/2003 77.766 193,514 1 10/3/2003 70.78 180,580 1 10/4/2003 77.717 197,639 1 10/5/2003 63.532 169,279 1 10/6/2003 74.317 196,516 1 10/7/2003 69.527 176,009 1 10/8/2003 46.857 187,470 1 10/9/2003 59.214 164,025 1 10/10/2003 76.928 183,433 1 10/11/2003 61.462 167,840 1 10/12/2003 67.021 157,181 1 10/13/2003 58.332 149,366 1 10/14/2003 54.619 152,338 1 10/15/2003 67.231 162,497 1 10/16/2003 51.32 139,546 1 10/17/2003 25.108 97,924 1 10/18/2003 31.745 97,235 1 10/19/2003 28.424 115,530 1 10/20/2003 71.574 172,790 1 10/21/2003 58.697 161,902 1 10/22/2003 51.816 140,425 1 10/23/2003 45.927 130,821 1 10/24/2003 62.545 161,974
1 10/25/2003 39.379 114,413 1 10/26/2003 44.288 142,423 1 10/27/2003 70.436 193,057 1 10/28/2003 89.193 215,641 1 10/29/2003 73.661 193,136 1 10/30/2003 74.113 208,511 1 10/31/2003 79.092 190,986 1 11/1/2003 83.82 210,706 1 11/2/2003 76.881 193,170 1 11/3/2003 88.042 215,517 1 11/4/2003 73.123 188,981 1 11/5/2003 83.25 215,410 1 11/6/2003 68.31 193,683 1 11/7/2003 78.174 205,225 1 11/8/2003 68.221 184,594 1 11/9/2003 76.211 207,142 1 11/10/2003 74.678 182,625 1 11/11/2003 62.183 147,918 1 11/12/2003 40.936 112,803 1 11/13/2003 59.962 147,031 1 11/14/2003 69.853 179,370 1 11/15/2003 58.64 199,238 1 11/16/2003 65.906 217,826 1 11/17/2003 66.262 198,597 1 11/18/2003 67.264 209,841 1 11/19/2003 66.151 196,649 1 11/20/2003 1.077 3,432 1 11/23/2003 25.616 89,769 1 11/24/2003 83.178 210,402 1 11/25/2003 47.086 130,602 1 11/26/2003 71.232 211,313 1 11/27/2003 70.576 186,143 1 11/28/2003 81.882 205,139 1 11/29/2003 57.244 183,532 1 11/30/2003 59.679 201,943 1 12/1/2003 58.438 186,624 1 12/2/2003 70.331 210,820 1 12/3/2003 28.762 118,238 1 12/7/2003 6.674 27,268 1 12/8/2003 67.963 191,589 1 12/9/2003 58.688 192,922 1 12/10/2003 71.468 201,157 1 12/11/2003 68.585 188,687 1 12/12/2003 65.425 196,780 1 12/13/2003 67.233 188,328 1 12/14/2003 79.576 195,868 1 12/15/2003 58.623 162,122
1 12/16/2003 60.004 170,922

1 12/17/2003 75.008 205,815

1 12/18/2003 73.319 179,105

1 12/19/2003 78.713 207,009

1 12/20/2003 42.448 140,551

1 12/21/2003 42.35 150,557

1 12/22/2003 69.795 203,348

1 12/23/2003 47.569 192,196

1 12/24/2003 45.567 177,562

1 12/25/2003 53.871 201,360

1 12/26/2003 49.882 194,279

1 12/27/2003 42.371 205,291

1 12/28/2003 38.072 181,144

1 12/29/2003 44.555 203,197

1 12/30/2003 38.917 189,748

1 12/31/2003 40.608 202,584

Max (tpd) --> 93.162

Max (lb/hr) --> 7763.5

Note: Dates with no operation/emissions not shown
 Unit ID Date

 SO2

(tons)

 Heat Input 

(MMBtu)

2 1/10/2001 0.754 33,637

2 1/11/2001 48.572 155,023

2 1/12/2001 69.767 223,001

2 1/13/2001 63.279 199,585

2 1/14/2001 70.944 196,874

2 1/15/2001 70.445 196,066

2 1/16/2001 71.084 214,936

2 1/17/2001 73.798 206,033

2 1/18/2001 80.818 228,270

2 1/19/2001 65.111 199,193

2 1/20/2001 82.298 228,161

2 1/21/2001 67.036 191,946

2 1/22/2001 82.267 231,789

2 1/23/2001 69.272 202,867

2 1/24/2001 67.477 203,133

2 1/25/2001 65.347 208,993

2 1/26/2001 72.167 221,736

2 1/27/2001 62.866 198,308

2 1/28/2001 64.123 208,264

2 1/29/2001 57.277 185,626

2 1/30/2001 71.366 213,747

2 1/31/2001 64.4 192,322

2 2/1/2001 74.805 220,513

2 2/2/2001 65.668 199,773

2 2/3/2001 76.063 219,848

2 2/4/2001 66.935 184,402

2 2/5/2001 73.809 217,446

2 2/6/2001 60.475 165,070

2 2/7/2001 59.292 172,471

2 2/8/2001 58.984 185,584

2 2/9/2001 51.92 154,356

2 2/10/2001 77.024 216,492

2 2/11/2001 59.475 187,862

2 2/12/2001 67.554 213,302

2 2/13/2001 59.31 183,263

2 2/14/2001 73.915 216,849

2 2/15/2001 56.155 185,480

2 2/16/2001 60.275 200,034

2 2/17/2001 60.896 185,447

2 2/18/2001 68.563 210,910

2 2/19/2001 63.536 192,921

2 2/20/2001 67.91 198,402

2 2/21/2001 65.391 193,429

2 2/22/2001 75.288 224,203

2 2/23/2001 66.278 200,474
2 2/24/2001 58.537 179,453 2 2/25/2001 59.957 181,189 2 2/26/2001 67.115 195,041 2 2/27/2001 60.745 174,238 2 2/28/2001 65.639 197,401 2 3/1/2001 62.668 184,455 2 3/2/2001 68.041 191,218 2 3/3/2001 57.07 171,070 2 3/4/2001 54.392 173,991 2 3/5/2001 65.951 197,817 2 3/6/2001 58.349 193,610 2 3/7/2001 78.118 223,725 2 3/8/2001 66.484 208,325 2 3/9/2001 69.273 191,776 2 3/10/2001 71.556 207,104 2 3/11/2001 56.766 160,681 2 3/12/2001 65.797 189,519 2 3/13/2001 63.754 186,465 2 3/14/2001 66.415 190,865 2 3/15/2001 63.324 185,756 2 3/16/2001 63.264 199,374 2 3/17/2001 60.518 184,595 2 3/18/2001 60.969 197,853 2 3/19/2001 66.76 197,346 2 3/20/2001 72.834 214,610 2 3/21/2001 61.998 188,273 2 3/22/2001 67.614 199,344 2 3/23/2001 60.426 186,547 2 3/24/2001 64.326 199,333 2 3/25/2001 53.746 174,018 2 3/26/2001 64.952 205,578 2 3/27/2001 64.971 193,287 2 3/28/2001 62.664 200,393 2 3/29/2001 59.724 185,695 2 3/30/2001 58.081 178,069 2 3/31/2001 68.646 191,096 2 4/1/2001 65.108 187,792 2 4/2/2001 57.317 202,604 2 4/3/2001 61.401 187,272 2 4/4/2001 58.343 194,899 2 4/5/2001 62.93 184,590 2 4/6/2001 59.78 191,757 2 4/7/2001 56.841 184,682 2 4/8/2001 69.676 190,946 2 4/9/2001 70.81 185,970 2 4/10/2001 54.723 197,849 2 4/11/2001 54.058 166,491
2 5/2/2001 4.915 25,051 2 5/3/2001 51.471 164,389 2 5/4/2001 70.899 214,110 2 5/5/2001 71.413 211,101 2 5/6/2001 63.354 193,817 2 5/7/2001 73.029 205,431 2 5/8/2001 68.396 200,902 2 5/9/2001 70.645 217,872 2 5/10/2001 67.923 208,187 2 5/11/2001 71.207 215,447 2 5/12/2001 62.622 180,366 2 5/13/2001 58.775 182,784 2 5/14/2001 68.965 197,405 2 5/15/2001 74.064 215,433 2 5/16/2001 66.586 197,138 2 5/17/2001 71.711 217,359 2 5/18/2001 70.055 206,643 2 5/19/2001 77.958 226,785 2 5/20/2001 68.772 204,157 2 5/21/2001 76.383 227,471 2 5/22/2001 58.712 177,827 2 5/23/2001 65.708 196,638 2 5/24/2001 63.432 189,095 2 5/25/2001 70.807 206,448 2 5/26/2001 65.271 193,677 2 5/27/2001 64.151 192,107 2 5/28/2001 52.023 150,016 2 5/29/2001 67.867 204,749 2 5/30/2001 67.63 199,560 2 5/31/2001 55.825 168,511 2 6/1/2001 62.407 184,927 2 6/2/2001 66.765 198,276 2 6/3/2001 67.295 208,569 2 6/4/2001 72.126 208,934 2 6/5/2001 73.841 217,607 2 6/6/2001 67.472 203,457 2 6/7/2001 69.52 206,278 2 6/8/2001 72.702 200,918 2 6/9/2001 71.159 210,583 2 6/10/2001 61.293 186,716 2 6/11/2001 65.811 203,227 2 6/12/2001 73.256 216,533 2 6/13/2001 76.688 225,531 2 6/14/2001 73.748 213,698 2 6/15/2001 73.415 210,730 2 6/16/2001 66.115 195,508 2 6/17/2001 69.267 201,585
2 6/18/2001 69.607 203,752 2 6/19/2001 70.868 205,665 2 6/20/2001 69.426 200,905 2 6/21/2001 74.099 214,438 2 6/22/2001 65.397 195,042 2 6/23/2001 71.333 204,508 2 6/24/2001 62.279 184,534 2 6/25/2001 69.734 206,170 2 6/26/2001 66.976 190,843 2 6/27/2001 66.883 201,570 2 6/28/2001 66.285 203,199 2 6/29/2001 72.059 202,362 2 6/30/2001 65.79 190,828 2 7/1/2001 63.437 186,111 2 7/2/2001 65.055 192,992 2 7/3/2001 77.963 205,510 2 7/4/2001 68.741 197,931 2 7/5/2001 68.553 197,585 2 7/6/2001 65.11 198,174 2 7/7/2001 74.56 213,383 2 7/8/2001 57.577 200,508 2 7/9/2001 62.687 223,282 2 7/10/2001 80.286 204,301 2 7/11/2001 80.159 221,400 2 7/12/2001 67.158 198,449 2 7/13/2001 80.201 221,335 2 7/14/2001 64.879 186,691 2 7/15/2001 68.191 179,878 2 7/16/2001 64.455 184,835 2 7/17/2001 47.578 174,526 2 7/18/2001 59.551 194,020 2 7/19/2001 70.542 213,198 2 7/20/2001 78.579 212,660 2 7/21/2001 71.753 217,047 2 7/22/2001 67.675 202,953 2 7/23/2001 68.944 210,570 2 7/24/2001 55.819 209,676 2 7/25/2001 62.294 230,575 2 7/26/2001 65.226 205,030 2 7/27/2001 68.019 202,340 2 7/28/2001 26.181 74,905 2 7/31/2001 15.582 46,223 2 8/1/2001 72.198 213,617 2 8/2/2001 68.602 216,562 2 8/3/2001 75.064 222,019 2 8/4/2001 65.508 206,369 2 8/5/2001 75.123 223,639
2 8/6/2001 60.963 209,754 2 8/7/2001 66.684 227,861 2 8/8/2001 68.328 233,054 2 8/9/2001 53.607 225,908 2 8/10/2001 56.111 212,219 2 8/11/2001 57.198 219,172 2 8/12/2001 62.849 207,576 2 8/13/2001 65.699 210,656 2 8/14/2001 61.753 203,483 2 8/15/2001 62.701 199,017 2 8/16/2001 68.982 213,177 2 8/17/2001 72.722 228,291 2 8/18/2001 66.308 208,089 2 8/19/2001 71.842 211,722 2 8/20/2001 66.222 203,776 2 8/21/2001 41.063 134,558 2 8/22/2001 73.13 219,632 2 8/23/2001 75.166 230,730 2 8/24/2001 69.238 218,750 2 8/25/2001 60.076 199,470 2 8/26/2001 65.824 205,122 2 8/27/2001 67.93 205,057 2 8/28/2001 66.653 207,979 2 8/29/2001 69.296 207,352 2 8/30/2001 71.494 227,618 2 8/31/2001 66.864 214,649 2 9/1/2001 71.312 223,891 2 9/2/2001 54.945 171,070 2 9/3/2001 58.511 203,589 2 9/4/2001 53.648 217,219 2 9/5/2001 77.724 229,361 2 9/6/2001 68.612 213,826 2 9/7/2001 76.503 226,878 2 9/8/2001 71.728 201,547 2 9/9/2001 66.574 193,595 2 9/10/2001 57.558 207,255 2 9/11/2001 72.633 230,033 2 9/12/2001 66.838 201,660 2 9/13/2001 73.934 227,204 2 9/14/2001 66.582 202,911 2 9/15/2001 59.653 186,297 2 9/16/2001 62.589 180,933 2 9/17/2001 66.522 204,906 2 9/18/2001 68.244 205,911 2 9/19/2001 74.626 226,638 2 9/20/2001 62.004 196,958 2 9/21/2001 56.879 205,070
2 9/22/2001 58.812 199,954 2 9/23/2001 58.074 198,779 2 9/24/2001 63.074 198,244 2 9/25/2001 62.399 184,066 2 9/26/2001 63.043 186,581 2 9/27/2001 66.482 200,156 2 9/28/2001 63.309 196,213 2 9/29/2001 62.67 194,975 2 9/30/2001 52.489 167,163 2 10/1/2001 64.268 201,430 2 10/2/2001 54.281 205,445 2 10/3/2001 62.915 218,269 2 10/4/2001 61.427 207,816 2 10/5/2001 69.979 226,059 2 10/6/2001 52.653 224,064 2 10/7/2001 62.748 204,980 2 10/8/2001 67.948 216,413 2 10/9/2001 69.421 215,028 2 10/10/2001 73.355 229,679 2 10/11/2001 62.266 208,230 2 10/12/2001 65.488 212,243 2 10/13/2001 58.759 186,099 2 10/14/2001 52.159 164,770 2 10/15/2001 62.781 199,326 2 10/16/2001 70.195 216,177 2 10/17/2001 64.077 202,867 2 10/18/2001 63.541 201,395 2 10/19/2001 57.453 184,769 2 10/20/2001 62.825 197,439 2 10/21/2001 66.511 204,790 2 10/22/2001 66.245 208,530 2 10/23/2001 67.053 216,718 2 10/24/2001 64.778 205,617 2 10/25/2001 58.75 192,113 2 10/26/2001 54.903 177,526 2 11/17/2001 1.436 32,899 2 11/18/2001 35.186 123,443 2 11/19/2001 49.752 170,295 2 11/20/2001 62.651 200,500 2 11/21/2001 55.149 181,063 2 11/22/2001 36.993 125,983 2 11/23/2001 38.869 125,294 2 11/24/2001 45.988 144,401 2 11/25/2001 43.804 151,134 2 11/26/2001 54.635 176,780 2 11/27/2001 62.528 200,430 2 11/28/2001 70.364 229,371
2 11/29/2001 66.22 213,787 2 11/30/2001 57.485 170,671 2 12/1/2001 63.727 197,244 2 12/2/2001 42.317 133,471 2 12/3/2001 59.164 200,205 2 12/4/2001 64.828 204,270 2 12/5/2001 68.503 212,388 2 12/6/2001 62.011 193,322 2 12/7/2001 75.636 222,251 2 12/8/2001 55.142 197,931 2 12/9/2001 57.054 188,726 2 12/10/2001 67.225 201,196 2 12/11/2001 74.844 226,565 2 12/12/2001 66.64 207,128 2 12/13/2001 67.535 207,164 2 12/14/2001 66.079 209,182 2 12/15/2001 66.339 235,036 2 12/16/2001 58.733 194,882 2 12/17/2001 64.843 211,213 2 12/18/2001 61.79 194,774 2 12/19/2001 64.132 202,373 2 12/20/2001 61.942 193,031 2 12/21/2001 68.826 222,563 2 12/22/2001 58.313 189,778 2 12/23/2001 53.796 190,558 2 12/24/2001 58.919 192,729 2 12/25/2001 52.663 176,095 2 12/26/2001 61.802 201,052 2 12/27/2001 71.321 223,889 2 12/28/2001 61.129 193,331 2 12/29/2001 69.055 224,118 2 12/30/2001 65.647 219,707 2 12/31/2001 52.399 227,640 2 1/1/2002 62.443 216,425 2 1/2/2002 70.702 232,973 2 1/3/2002 75.864 245,312 2 1/4/2002 70.449 221,367 2 1/5/2002 73.951 237,679 2 1/6/2002 63.773 208,778 2 1/7/2002 67.44 226,227 2 1/8/2002 46.998 159,482 2 1/9/2002 62.622 212,629 2 1/10/2002 61.763 204,240 2 1/11/2002 62.735 204,685 2 1/12/2002 58.128 189,070 2 1/13/2002 63.343 205,872 2 1/14/2002 39.41 120,321
2 1/19/2002 1.37 10,837 2 1/20/2002 56.205 195,467 2 1/21/2002 72.29 230,019 2 1/22/2002 57.036 186,395 2 1/23/2002 61.568 197,176 2 1/24/2002 55.53 184,772 2 1/25/2002 58.035 191,601 2 1/26/2002 51.602 174,901 2 1/27/2002 52.553 178,355 2 1/28/2002 50.679 152,352 2 1/29/2002 60.533 187,478 2 1/30/2002 58.67 193,409 2 1/31/2002 63.564 197,722 2 2/1/2002 60.209 195,293 2 2/2/2002 64.681 203,080 2 2/3/2002 54.381 171,970 2 2/4/2002 66.661 210,080 2 2/5/2002 67.477 205,471 2 2/6/2002 70.912 222,089 2 2/7/2002 61.621 194,478 2 2/8/2002 62.479 199,087 2 2/9/2002 55.252 182,193 2 2/10/2002 60.083 189,205 2 2/11/2002 58.505 187,336 2 2/12/2002 61.278 200,113 2 2/13/2002 62.493 200,276 2 2/14/2002 53.959 211,516 2 2/15/2002 51.148 204,465 2 2/16/2002 68.171 218,723 2 2/17/2002 50.575 171,532 2 2/18/2002 59.098 204,245 2 2/19/2002 50.629 166,054 2 2/21/2002 0.026 781 2 2/23/2002 18.532 70,454 2 2/24/2002 52.372 189,719 2 2/25/2002 65.295 201,438 2 2/26/2002 56.154 208,396 2 2/27/2002 72.037 236,746 2 2/28/2002 64.238 208,195 2 3/1/2002 58.331 195,938 2 3/2/2002 63.246 206,102 2 3/3/2002 71.965 224,207 2 3/4/2002 70.551 221,266 2 3/5/2002 64.458 199,553 2 3/6/2002 68.816 222,032 2 3/7/2002 61.224 195,503 2 3/8/2002 67.506 216,459
2 3/9/2002 61.484 196,156 2 3/10/2002 70.586 223,914 2 3/11/2002 62.045 203,806 2 3/12/2002 69.607 228,031 2 3/13/2002 56.569 190,646 2 3/14/2002 56.669 230,970 2 3/15/2002 52.218 180,817 2 4/2/2002 1.005 7,048 2 4/3/2002 30.442 98,839 2 4/4/2002 71.24 213,172 2 4/5/2002 64.366 196,330 2 4/6/2002 70.825 211,075 2 4/7/2002 67.165 203,299 2 4/8/2002 67.72 207,416 2 4/9/2002 64.94 196,108 2 4/10/2002 66.561 211,263 2 4/11/2002 31.135 105,732 2 4/12/2002 66.671 201,828 2 4/13/2002 70.558 215,952 2 4/14/2002 62.103 195,979 2 4/15/2002 69.001 209,466 2 4/16/2002 60.639 205,080 2 4/17/2002 61.127 199,518 2 4/18/2002 54.461 206,262 2 4/19/2002 62.814 211,213 2 4/20/2002 67.041 218,172 2 4/21/2002 63.153 206,199 2 4/22/2002 72.421 225,344 2 4/23/2002 68.627 202,654 2 4/24/2002 69.78 213,992 2 4/25/2002 63.821 199,226 2 4/26/2002 66.662 207,529 2 4/27/2002 67.558 197,847 2 4/28/2002 78.7 217,106 2 4/29/2002 69.386 198,134 2 4/30/2002 68.806 207,862 2 5/1/2002 74.322 199,942 2 5/2/2002 79.624 225,804 2 5/3/2002 63.515 188,412 2 5/4/2002 73.497 212,408 2 5/5/2002 64.424 191,681 2 5/6/2002 70.065 214,917 2 5/7/2002 54.22 166,496 2 5/8/2002 1.497 5,124 2 7/14/2002 0.049 12,297 2 7/15/2002 12.132 63,796 2 7/16/2002 28.317 102,351
2 7/17/2002 33.698 110,894 2 7/18/2002 37.537 113,716 2 7/19/2002 40.27 117,689 2 7/20/2002 38.357 117,244 2 7/21/2002 38.988 118,885 2 7/22/2002 40.61 125,594 2 7/23/2002 42.915 131,892 2 7/24/2002 40.241 123,002 2 7/25/2002 37.361 115,289 2 7/27/2002 0 2,084 2 7/28/2002 26.878 101,064 2 7/29/2002 41.445 132,686 2 7/30/2002 42.387 132,270 2 7/31/2002 38.205 119,888 2 8/1/2002 39.95 129,553 2 8/2/2002 40.337 125,598 2 8/3/2002 42.239 132,488 2 8/4/2002 42.95 133,154 2 8/5/2002 43.385 130,753 2 8/6/2002 40.455 125,782 2 8/7/2002 43.123 129,834 2 8/8/2002 43.569 128,427 2 8/9/2002 43.707 130,776 2 8/10/2002 43.608 122,620 2 8/11/2002 46.613 130,424 2 8/12/2002 45.51 130,658 2 8/13/2002 45.872 130,659 2 8/14/2002 41.298 122,162 2 8/15/2002 42.519 129,385 2 8/16/2002 40.682 131,262 2 8/17/2002 42.923 125,941 2 8/18/2002 35.574 112,584 2 8/19/2002 36.749 117,565 2 8/20/2002 40.825 126,432 2 8/21/2002 42.211 132,139 2 8/22/2002 44.507 133,130 2 8/23/2002 38.883 123,059 2 8/24/2002 43.506 133,585 2 8/25/2002 42.62 129,702 2 8/26/2002 42.974 129,878 2 8/27/2002 40.749 125,442 2 8/28/2002 43.644 132,711 2 8/29/2002 43.262 130,706 2 8/30/2002 42.692 127,650 2 8/31/2002 42.006 122,818 2 9/1/2002 37.586 129,007 2 9/2/2002 42.465 131,335
2 9/3/2002 46.488 133,977 2 9/4/2002 48.912 127,093 2 9/5/2002 48.428 134,055 2 9/6/2002 44.812 133,846 2 9/7/2002 47.637 133,684 2 9/8/2002 43.014 125,865 2 9/9/2002 42.505 134,267 2 9/10/2002 44.97 133,966 2 9/11/2002 46.077 134,731 2 9/12/2002 38.94 127,494 2 9/13/2002 43.019 133,298 2 9/14/2002 43.498 133,266 2 9/15/2002 41.546 133,852 2 9/16/2002 38.665 127,547 2 9/17/2002 40.004 132,831 2 9/18/2002 42.416 133,344 2 9/19/2002 43.755 132,879 2 9/20/2002 39.322 127,258 2 9/21/2002 42.757 132,226 2 9/22/2002 44.43 131,967 2 9/23/2002 43.747 131,537 2 9/24/2002 39.868 119,834 2 9/25/2002 43.73 129,196 2 9/26/2002 40.585 129,194 2 9/27/2002 43.31 132,513 2 9/28/2002 43.877 122,563 2 9/29/2002 46.965 130,039 2 9/30/2002 44.132 133,787 2 10/1/2002 44.799 133,059 2 10/2/2002 43.21 126,877 2 10/3/2002 46.862 131,501 2 10/4/2002 47.388 134,040 2 10/5/2002 46.533 132,296 2 10/6/2002 37.951 129,378 2 10/7/2002 37.966 134,015 2 10/8/2002 52.868 131,411 2 10/9/2002 48.696 130,423 2 10/10/2002 42.076 126,447 2 10/11/2002 43.721 132,825 2 10/12/2002 40.764 133,441 2 10/13/2002 41.794 131,590 2 10/14/2002 43.046 124,950 2 10/15/2002 42.015 131,725 2 10/16/2002 41.245 130,847 2 10/17/2002 42.07 125,099 2 10/18/2002 42.819 125,107 2 10/19/2002 45.384 132,512
2 10/20/2002 41.747 122,107 2 10/21/2002 46.708 127,818 2 10/22/2002 39.902 124,298 2 10/23/2002 46.263 131,562 2 10/24/2002 47.766 131,047 2 10/25/2002 41.849 124,779 2 10/26/2002 41.564 123,656 2 10/27/2002 43.533 129,717 2 10/28/2002 43.741 130,411 2 10/29/2002 51.355 131,682 2 10/30/2002 45.219 125,490 2 10/31/2002 44.394 127,462 2 11/1/2002 44.205 129,628 2 11/2/2002 44.643 129,261 2 11/3/2002 40.96 123,745 2 11/4/2002 44.925 129,527 2 11/5/2002 44.343 129,860 2 11/6/2002 39.085 128,247 2 11/7/2002 39.211 116,214 2 11/8/2002 0.112 713 2 11/9/2002 30.216 89,527 2 11/10/2002 42.778 132,346 2 11/11/2002 45.237 135,241 2 11/12/2002 42.721 133,800 2 11/13/2002 40.472 126,955 2 11/14/2002 43.795 134,896 2 11/15/2002 43.198 131,216 2 11/16/2002 45.042 131,855 2 11/17/2002 38.768 124,964 2 11/18/2002 45.241 134,505 2 11/19/2002 43.17 128,974 2 11/20/2002 44.857 133,926 2 11/21/2002 34.507 124,369 2 11/22/2002 40.563 134,614 2 11/23/2002 41.97 126,004 2 11/24/2002 42.291 130,382 2 11/25/2002 41.495 124,334 2 11/26/2002 37.269 124,510 2 11/27/2002 49.643 130,574 2 11/28/2002 39.346 117,870 2 11/29/2002 36.85 112,104 2 11/30/2002 38.929 116,062 2 12/1/2002 43.494 125,327 2 12/2/2002 43.673 128,968 2 12/3/2002 44.758 128,720 2 12/4/2002 40.619 120,228 2 12/5/2002 44.174 123,841
2 12/6/2002 45.294 122,380 2 12/7/2002 44.022 130,355 2 12/8/2002 39.016 125,323 2 12/9/2002 39.942 128,946 2 12/10/2002 45.545 129,204 2 12/11/2002 46.137 129,573 2 12/12/2002 42.167 122,406 2 12/13/2002 43.991 125,979 2 12/14/2002 42.538 122,758 2 12/15/2002 44.708 118,376 2 12/16/2002 44.316 119,716 2 12/17/2002 50.162 133,839 2 12/18/2002 46.255 134,021 2 12/19/2002 45.517 126,790 2 12/20/2002 40.965 115,263 2 12/21/2002 41.574 121,203 2 12/22/2002 39.851 114,174 2 12/23/2002 46.372 130,222 2 12/24/2002 42.257 121,970 2 12/25/2002 43.695 124,949 2 12/26/2002 45.922 131,297 2 12/27/2002 42.103 126,936 2 12/28/2002 41.979 125,825 2 12/29/2002 41.407 130,355 2 12/30/2002 39.035 125,098 2 12/31/2002 33.961 106,812 2 1/1/2003 0.341 1,291 2 1/2/2003 24.871 75,015 2 1/3/2003 43.488 131,086 2 1/4/2003 44.772 133,140 2 1/5/2003 43.777 127,572 2 1/6/2003 41.851 127,057 2 1/7/2003 43.265 129,584 2 1/8/2003 33.494 135,839 2 1/9/2003 34.51 117,031 2 1/10/2003 32.859 105,555 2 1/11/2003 45.679 133,252 2 1/12/2003 47.269 131,567 2 1/13/2003 43.467 131,756 2 1/14/2003 34.278 121,976 2 1/15/2003 37.056 126,788 2 1/16/2003 35.639 124,641 2 1/17/2003 40.614 126,291 2 1/18/2003 27.459 85,135 2 1/19/2003 17.771 59,166 2 1/20/2003 35.263 109,848 2 1/21/2003 35.953 123,177
2 1/22/2003 37.714 131,248 2 1/23/2003 35.122 129,180 2 1/24/2003 36.233 127,447 2 1/25/2003 39.378 127,484 2 1/26/2003 40.25 132,336 2 1/27/2003 40.483 128,508 2 1/28/2003 37.561 124,953 2 1/29/2003 38.808 128,100 2 1/30/2003 35.494 130,346 2 1/31/2003 38.757 133,533 2 2/1/2003 41.725 127,852 2 2/2/2003 40.329 120,575 2 2/3/2003 42.013 132,787 2 2/4/2003 43.945 124,794 2 2/5/2003 51.338 123,725 2 2/6/2003 41.152 131,622 2 2/7/2003 45.95 131,172 2 2/8/2003 43.205 130,678 2 2/9/2003 36.771 121,808 2 2/10/2003 33.438 126,701 2 2/11/2003 35.582 123,701 2 2/12/2003 47.622 134,658 2 2/13/2003 38.8 124,207 2 2/14/2003 44.771 131,396 2 2/15/2003 46.803 134,435 2 2/16/2003 45.905 132,770 2 2/17/2003 41.288 133,121 2 2/18/2003 45.265 131,622 2 2/19/2003 42.955 126,106 2 2/20/2003 43.088 128,814 2 2/21/2003 38.065 117,061 2 2/22/2003 24.402 77,292 2 2/23/2003 29.682 90,028 2 2/24/2003 40.007 131,088 2 2/25/2003 38.767 126,340 2 2/26/2003 36.996 121,711 2 2/27/2003 35.323 129,456 2 2/28/2003 38.09 123,264 2 3/1/2003 40.001 116,912 2 3/2/2003 40.728 125,999 2 3/3/2003 33.138 132,172 2 3/4/2003 20.669 79,737 2 3/5/2003 36.366 137,002 2 3/6/2003 34.559 126,821 2 3/7/2003 33.253 114,835 2 4/22/2003 0.024 2,455 2 4/23/2003 0.57 6,409
2 4/24/2003 0.346 4,998 2 4/25/2003 1.653 19,701 2 4/26/2003 1.182 11,608 2 4/27/2003 1.331 10,900 2 4/28/2003 27.687 97,392 2 4/29/2003 23.224 72,650 2 5/4/2003 0.227 2,424 2 5/5/2003 17.06 57,849 2 5/6/2003 30.047 78,658 2 5/7/2003 46.492 142,062 2 5/8/2003 72.41 213,935 2 5/9/2003 68.937 207,975 2 5/10/2003 74.992 230,885 2 5/11/2003 67.38 200,812 2 5/12/2003 70.581 210,656 2 5/13/2003 57.171 171,045 2 5/14/2003 70.563 200,534 2 5/15/2003 70.167 202,730 2 5/16/2003 72.346 205,881 2 5/17/2003 58.061 185,961 2 5/18/2003 19.448 115,299 2 5/19/2003 31.077 101,821 2 5/20/2003 22.744 99,360 2 5/21/2003 25.872 89,078 2 5/22/2003 36.635 120,936 2 5/23/2003 48.567 147,872 2 5/24/2003 52.07 156,613 2 5/25/2003 46.489 143,001 2 5/26/2003 58.979 174,641 2 5/27/2003 55.063 161,496 2 5/28/2003 65.86 179,119 2 5/29/2003 55.553 174,322 2 5/30/2003 60.648 208,039 2 5/31/2003 71.727 198,338 2 6/1/2003 70.761 212,833 2 6/2/2003 61.365 203,050 2 6/3/2003 68.958 210,743 2 6/4/2003 62.461 182,842 2 6/5/2003 62.573 183,088 2 6/6/2003 34.208 115,096 2 6/7/2003 65.11 197,511 2 6/8/2003 62.324 181,844 2 6/9/2003 63.884 191,746 2 6/10/2003 63.19 201,659 2 6/11/2003 72.437 206,864 2 6/12/2003 58.341 175,572 2 6/13/2003 56.284 179,098
2 6/14/2003 61.374 193,446 2 6/15/2003 57.086 189,912 2 6/16/2003 55.164 189,091 2 6/17/2003 62.629 196,250 2 6/18/2003 64.786 189,691 2 6/19/2003 73.637 211,207 2 6/20/2003 63.431 197,470 2 6/21/2003 63.918 197,410 2 6/22/2003 64.29 198,094 2 6/23/2003 75.428 227,341 2 6/24/2003 66.436 202,040 2 6/25/2003 72.313 226,759 2 6/26/2003 66.525 197,524 2 6/27/2003 68.121 197,548 2 6/28/2003 63.802 200,025 2 6/29/2003 77.756 220,554 2 6/30/2003 52.714 170,043 2 7/1/2003 71.656 214,756 2 7/2/2003 63.08 186,501 2 7/3/2003 73.932 215,785 2 7/4/2003 60.631 178,823 2 7/5/2003 68.874 205,836 2 7/6/2003 61.564 178,612 2 7/7/2003 74.013 223,042 2 7/8/2003 67.694 208,792 2 7/9/2003 76.708 221,622 2 7/10/2003 68.181 197,469 2 7/11/2003 66.898 195,582 2 7/12/2003 59.027 207,695 2 7/13/2003 75.38 218,117 2 7/14/2003 69.033 203,421 2 7/15/2003 78.388 230,380 2 7/16/2003 74.257 203,521 2 7/17/2003 75.934 217,919 2 7/18/2003 68.109 191,966 2 7/19/2003 72.846 207,656 2 7/20/2003 61.14 178,396 2 7/21/2003 78.679 230,258 2 7/22/2003 62.621 195,532 2 7/23/2003 65.829 203,912 2 7/24/2003 60.599 178,711 2 7/25/2003 73.576 210,531 2 7/26/2003 70.157 197,491 2 7/27/2003 90.528 215,849 2 7/28/2003 68.841 191,139 2 7/29/2003 70.723 204,797 2 7/30/2003 67.712 197,828
2 7/31/2003 66.125 202,486 2 8/1/2003 71.541 196,492 2 8/2/2003 80.742 214,317 2 8/3/2003 61.329 168,613 2 8/4/2003 68.92 195,435 2 8/5/2003 61.499 178,308 2 8/6/2003 73.18 207,756 2 8/7/2003 69.856 190,980 2 8/8/2003 77.228 187,873 2 8/9/2003 72.809 191,248 2 8/10/2003 75.267 200,240 2 8/11/2003 60.618 154,754 2 8/12/2003 63.981 167,678 2 8/13/2003 74.526 186,716 2 8/14/2003 82.677 219,956 2 8/15/2003 69.953 198,724 2 8/16/2003 78.945 219,751 2 8/17/2003 84.556 185,941 2 8/18/2003 87.543 217,540 2 8/19/2003 74.519 199,463 2 8/20/2003 88.865 221,338 2 8/21/2003 70.209 187,889 2 8/22/2003 81.354 217,865 2 8/23/2003 77.177 179,597 2 8/24/2003 62.13 172,445 2 8/25/2003 68.592 194,288 2 8/26/2003 87.919 203,448 2 8/27/2003 80.932 216,513 2 8/28/2003 82.687 197,918 2 8/29/2003 82.208 202,540 2 8/30/2003 83.364 211,336 2 8/31/2003 65.314 183,922 2 9/1/2003 93.901 216,245 2 9/2/2003 67.103 195,437 2 9/3/2003 87.882 211,604 2 9/4/2003 73.831 185,708 2 9/5/2003 62.172 169,129 2 9/6/2003 69.933 172,549 2 9/7/2003 71.082 186,768 2 9/8/2003 67.777 194,007 2 9/9/2003 59.869 208,235 2 9/10/2003 47.297 191,134 2 9/11/2003 70.439 214,754 2 9/12/2003 68.502 194,246 2 9/13/2003 77.372 212,995 2 9/14/2003 62.285 185,112 2 9/15/2003 62.138 181,443
2 9/16/2003 54.365 159,836 2 9/17/2003 44.087 170,662 2 9/18/2003 64.266 179,510 2 9/19/2003 84.561 198,395 2 9/20/2003 61.237 175,201 2 9/21/2003 45.248 135,969 2 9/22/2003 64.048 184,563 2 9/23/2003 72.375 210,158 2 9/24/2003 67.512 190,162 2 9/25/2003 82.877 216,409 2 9/26/2003 66.416 195,764 2 9/27/2003 71.255 214,105 2 9/28/2003 48.564 144,440 2 10/1/2003 0.739 5,350 2 10/2/2003 33.504 91,269 2 10/3/2003 69.337 173,240 2 10/4/2003 70.961 181,775 2 10/5/2003 78.203 208,329 2 10/6/2003 75.187 201,250 2 10/7/2003 89.169 220,542 2 10/8/2003 49.203 193,751 2 10/9/2003 67.662 186,810 2 10/10/2003 79.918 191,964 2 10/11/2003 77.311 208,470 2 10/12/2003 55.02 133,243 2 10/13/2003 57.783 146,579 2 10/14/2003 57.2 158,381 2 10/15/2003 70.099 163,846 2 10/16/2003 39.172 119,677 2 10/17/2003 22.491 110,018 2 10/18/2003 28.818 111,833 2 10/19/2003 26.99 97,703 2 10/20/2003 47.314 136,379 2 10/21/2003 58.792 171,856 2 10/22/2003 44.082 123,176 2 10/23/2003 38.065 108,419 2 10/24/2003 46.912 121,940 2 10/25/2003 40.834 121,636 2 10/26/2003 41.361 134,381 2 10/27/2003 77.893 217,120 2 10/28/2003 81.213 189,818 2 10/29/2003 88.045 219,499 2 10/30/2003 69.841 189,813 2 10/31/2003 88.683 217,110 2 11/1/2003 73.396 187,086 2 11/2/2003 83.102 204,959 2 11/3/2003 78.948 190,234
2 11/4/2003 82.853 207,766 2 11/5/2003 80.004 205,747 2 11/6/2003 72.8 209,571 2 11/7/2003 68.317 179,234 2 11/8/2003 78.886 216,308 2 11/9/2003 66.667 184,689 2 11/10/2003 78.976 195,905 2 11/11/2003 52.075 130,022 2 11/12/2003 41.692 117,091 2 11/13/2003 11.611 36,258 2 11/17/2003 0.17 2,225 2 11/18/2003 38.966 117,867 2 11/19/2003 65.18 198,434 2 11/20/2003 71.803 194,782 2 11/21/2003 83.116 211,544 2 11/22/2003 70.553 193,300 2 11/23/2003 74.376 201,621 2 11/24/2003 77.352 199,592 2 11/25/2003 80.788 215,593 2 11/26/2003 63.023 192,250 2 11/27/2003 63.937 183,110 2 11/28/2003 68.873 184,297 2 11/29/2003 66.042 216,610 2 11/30/2003 46.244 167,797 2 12/1/2003 57.318 183,858 2 12/2/2003 63.35 181,812 2 12/3/2003 56.658 195,654 2 12/4/2003 65.813 180,092 2 12/5/2003 58.821 198,595 2 12/6/2003 54.429 201,880 2 12/7/2003 87.118 207,001 2 12/8/2003 61.162 166,563 2 12/9/2003 65.51 208,456 2 12/10/2003 73.371 197,599 2 12/11/2003 81.449 210,498 2 12/12/2003 60.767 176,633 2 12/13/2003 75.382 202,675 2 12/14/2003 68.046 166,486 2 12/15/2003 76.107 200,848 2 12/16/2003 59.007 163,400 2 12/17/2003 74.676 202,708 2 12/18/2003 80.577 193,320 2 12/19/2003 71.731 183,867 2 12/20/2003 71.602 216,101 2 12/21/2003 57.933 178,546 2 12/22/2003 56.158 161,064 2 12/23/2003 47.942 181,785
2 12/24/2003 56.125 196,775

2 12/25/2003 51.062 177,009

2 12/26/2003 54.125 196,221

2 12/27/2003 40.469 186,754

2 12/28/2003 41.98 191,214

2 12/29/2003 40.674 182,939

2 12/30/2003 44.935 209,032

2 12/31/2003 42.973 185,415

Max (tpd) --> 93.901

Max (lb/hr) --> 7825.1

Note: Dates with no operation/emissions not shown
 Unit ID Date

 Avg. NOx Rate 

(lb/MMBtu)

 NOx 

(tons)

 Heat Input 

(MMBtu)

1 1/1/2009 0.2417 22.557 185,974 1 1/2/2009 0.229 21.102 183,955 1 1/3/2009 0.2418 21.9 178,066 1 1/4/2009 0.3366 29.789 180,075 1 1/5/2009 0.3364 31.511 187,206 1 1/6/2009 0.3416 32.861 192,024 1 1/7/2009 0.3303 31.933 193,023 1 1/8/2009 0.3044 29.676 194,965 1 1/9/2009 0.2255 20.636 182,247 1 1/10/2009 0.2662 18.387 144,944 1 1/11/2009 0.2362 20.178 172,039 1 1/12/2009 0.2348 22.039 186,247 1 1/13/2009 0.2088 16.731 158,242 1 1/14/2009 0.172 11.413 132,759 1 1/15/2009 0.1951 12.023 120,430 1 1/16/2009 0.2145 13.936 129,923 1 1/17/2009 0.1877 1.053 8,769 1 1/19/2009 0.0508 0.224 6,180 1 1/20/2009 0.2751 22.771 172,042 1 1/21/2009 0.2678 27.201 203,889 1 1/22/2009 0.2832 28.739 202,984 1 1/23/2009 0.2964 29.004 195,578 1 1/24/2009 0.2543 22.006 181,460 1 1/25/2009 0.2193 21.944 199,901 1 1/26/2009 0.2823 27.765 196,432 1 1/27/2009 0.2893 23.969 166,298 1 1/28/2009 0.2787 21.49 156,515 1 1/29/2009 0.2604 22.952 175,543 1 1/30/2009 0.2155 16.605 153,462 1 1/31/2009 0.2364 14.627 124,976 1 2/1/2009 0.252 20.969 166,864 1 2/2/2009 0.2503 19.149 155,816 1 2/3/2009 0.2304 21.501 187,220 1 2/4/2009 0.2326 21.196 182,571 1 2/5/2009 0.2295 18.233 156,315 1 2/6/2009 0.2191 21.27 194,417 1 2/7/2009 0.2425 22.265 187,834 1 2/8/2009 0.2223 22.37 201,308 1 2/9/2009 0.2375 23.27 195,674 1 2/10/2009 0.2649 24.645 185,718 1 2/11/2009 0.2936 26.569 180,885 1 2/12/2009 0.2832 27.88 197,109 1 2/13/2009 0.2948 29.084 197,610 1 2/14/2009 0.2948 23.967 165,802 1 2/15/2009 0.2688 25.925 193,017
1 2/16/2009 0.2419 22.894 189,774 1 2/17/2009 0.2365 22.752 193,112 1 2/18/2009 0.2326 20.909 179,771 1 2/19/2009 0.2327 16.466 129,297 1 2/20/2009 0.2777 24.159 173,092 1 2/21/2009 0.3317 28.161 172,865 1 2/22/2009 0.2971 26.247 177,509 1 2/23/2009 0.2568 24.565 191,481 1 2/24/2009 0.2597 24.822 190,964 1 2/25/2009 0.2659 23.68 178,208 1 2/26/2009 0.2962 26.941 181,698 1 2/27/2009 0.2946 25.36 175,220 1 2/28/2009 0.2531 21.377 170,065 1 3/1/2009 0.2629 25.952 197,521 1 3/2/2009 0.2688 26.674 198,445 1 3/3/2009 0.2677 26.519 198,236 1 3/4/2009 0.2792 26.801 190,996 1 3/5/2009 0.2172 20.312 186,838 1 3/6/2009 0.2316 23.537 202,821 1 3/7/2009 0.2378 18.594 157,394 1 3/8/2009 0.2346 21.958 187,077 1 3/9/2009 0.2279 20.968 181,867 1 3/10/2009 0.2394 23.077 190,866 1 3/11/2009 0.2459 24.583 200,550 1 3/12/2009 0.2488 22.693 182,849 1 3/13/2009 0.226 22.412 198,704 1 3/14/2009 0.2755 25.641 188,369 1 3/15/2009 0.242 23.083 191,574 1 3/16/2009 0.2407 23.256 193,804 1 3/17/2009 0.2453 23.086 189,229 1 3/18/2009 0.2315 23.342 201,601 1 3/19/2009 0.2322 22.393 192,481 1 3/20/2009 0.2223 21.275 190,261 1 3/21/2009 0.2848 25.606 182,647 1 3/22/2009 0.2231 20.163 180,672 1 3/23/2009 0.2219 20.184 182,865 1 3/24/2009 0.227 20.394 179,816 1 3/25/2009 0.2252 17.466 155,017 1 3/26/2009 0.3166 22.005 139,523 1 3/27/2009 0.2665 20.626 159,139 1 3/28/2009 0.2748 22.249 163,292 1 3/29/2009 0.2876 24.313 169,540 1 3/30/2009 0.2566 18.694 147,977 1 3/31/2009 0.2418 20.157 170,786 1 4/1/2009 0.2425 20.385 169,170 1 4/2/2009 0.2625 23.178 175,663 1 4/3/2009 0.2749 7.911 59,243
1 5/28/2009 0.0287 0.083 6,885 1 5/29/2009 0.0786 1.378 19,230 1 5/30/2009 0.2526 10.539 85,244 1 5/31/2009 0.0899 1.982 20,766 1 6/1/2009 0.26 15.038 122,900 1 6/3/2009 0.1327 7.661 62,957 1 6/4/2009 0.2477 16.053 138,038 1 6/5/2009 0.199 14.148 144,774 1 6/6/2009 0.2236 16.432 157,342 1 6/7/2009 0.2445 21.247 168,616 1 6/8/2009 0.2495 21.429 171,595 1 6/9/2009 0.2165 18.829 176,195 1 6/10/2009 0.2166 19.84 182,888 1 6/11/2009 0.2525 19.041 152,239 1 6/12/2009 0.2261 15.507 129,907 1 6/13/2009 0.229 16.4 148,419 1 6/14/2009 0.2191 15.878 147,645 1 6/15/2009 0.2167 19.406 175,677 1 6/16/2009 0.2202 18.626 167,794 1 6/17/2009 0.2194 20.474 186,024 1 6/18/2009 0.224 19.253 172,835 1 6/19/2009 0.227 20.813 184,848 1 6/20/2009 0.2731 24.007 177,114 1 6/21/2009 0.2538 24.095 191,110 1 6/22/2009 0.2253 21.912 194,107 1 6/23/2009 0.2313 22.821 197,316 1 6/24/2009 0.2539 24.536 192,962 1 6/25/2009 0.27 25.93 192,250 1 6/26/2009 0.2407 22.151 183,922 1 6/27/2009 0.2341 23.052 196,801 1 6/28/2009 0.2227 18.801 169,557 1 6/29/2009 0.214 16.968 157,727 1 6/30/2009 0.2357 16.931 140,820 1 7/1/2009 0.2701 21.895 161,488 1 7/2/2009 0.2266 19.26 169,047 1 7/3/2009 0.2322 21.273 183,230 1 7/4/2009 0.2604 19.154 152,742 1 7/5/2009 0.2276 17.629 153,938 1 7/6/2009 0.2195 18.51 168,092 1 7/7/2009 0.2192 20.064 182,222 1 7/8/2009 0.2178 19.794 180,994 1 7/9/2009 0.2311 21.53 185,874 1 7/10/2009 0.2643 23.126 180,863 1 7/11/2009 0.231 21.777 187,959 1 7/12/2009 0.2395 22.676 188,909 1 7/13/2009 0.2328 22.305 191,569 1 7/14/2009 0.2259 19.839 174,964
1 7/15/2009 0.2104 18.974 178,437 1 7/16/2009 0.279 24.991 178,594 1 7/17/2009 0.268 22.174 163,644 1 7/18/2009 0.3062 21.149 139,841 1 7/19/2009 0.2583 15.447 131,234 1 7/20/2009 0.2221 17.685 157,902 1 7/21/2009 0.2088 17.162 162,416 1 7/22/2009 0.2248 18.977 168,446 1 7/23/2009 0.2218 21.006 189,176 1 7/24/2009 0.2592 22.812 174,486 1 7/25/2009 0.2445 19.792 172,882 1 7/26/2009 0.2194 19.74 178,570 1 7/27/2009 0.2739 25.05 184,085 1 7/28/2009 0.2653 23.752 178,477 1 7/29/2009 0.259 22.421 173,100 1 7/30/2009 0.2096 14.423 137,320 1 8/1/2009 0.1339 5.494 51,274 1 8/2/2009 0.2293 20.221 176,461 1 8/3/2009 0.218 21.863 200,576 1 8/4/2009 0.2283 22.657 198,572 1 8/5/2009 0.2138 20.259 189,372 1 8/6/2009 0.217 19.174 176,305 1 8/7/2009 0.2181 20.147 184,761 1 8/8/2009 0.2771 24.472 177,359 1 8/9/2009 0.2812 27.31 193,766 1 8/10/2009 0.2857 28.233 197,731 1 8/11/2009 0.2744 26.897 196,156 1 8/12/2009 0.2698 24.817 182,817 1 8/13/2009 0.269 24.551 181,456 1 8/14/2009 0.2743 26.741 195,153 1 8/15/2009 0.2836 24.237 174,577 1 8/16/2009 0.2333 22.542 193,038 1 8/17/2009 0.272 26.42 194,019 1 8/18/2009 0.2321 21.397 184,088 1 8/19/2009 0.2271 20.926 183,818 1 8/20/2009 0.236 20.698 175,508 1 8/21/2009 0.2556 21.222 164,035 1 8/22/2009 0.2527 20.179 166,278 1 8/23/2009 0.288 22.807 161,085 1 8/24/2009 0.2919 24.46 167,101 1 8/25/2009 0.2717 23.916 175,933 1 8/26/2009 0.2889 25.766 177,843 1 8/27/2009 0.2782 25.141 180,206 1 8/28/2009 0.2753 26.642 193,609 1 8/29/2009 0.2828 23.682 169,967 1 8/30/2009 0.2709 22.767 171,656 1 8/31/2009 0.2385 20.603 172,786
1 9/1/2009 0.2895 23.532 165,149 1 9/2/2009 0.2393 20.326 171,089 1 9/3/2009 0.2754 25.441 182,556 1 9/4/2009 0.2936 28.943 197,227 1 9/5/2009 0.2339 19.971 172,357 1 9/6/2009 0.2321 20.473 176,563 1 9/7/2009 0.2785 23.08 166,814 1 9/8/2009 0.2849 26.244 182,516 1 9/9/2009 0.2972 29.066 195,567 1 9/10/2009 0.3008 29.164 193,968 1 9/11/2009 0.2925 27.837 190,060 1 9/12/2009 0.309 25.17 164,710 1 9/13/2009 0.2767 22.257 159,705 1 9/14/2009 0.2844 26.049 182,422 1 9/15/2009 0.2845 27.594 193,972 1 9/16/2009 0.2789 26.122 187,725 1 9/17/2009 0.2723 26.244 192,695 1 9/18/2009 0.2669 25.69 192,762 1 9/19/2009 0.2603 21.785 172,989 1 9/20/2009 0.2673 24.945 185,873 1 9/21/2009 0.2783 27.284 196,072 1 9/22/2009 0.2793 24.525 174,692 1 9/23/2009 0.2764 25.169 181,883 1 9/24/2009 0.2818 23.014 163,024 1 9/25/2009 0.254 22.424 176,232 1 9/26/2009 0.3217 25.439 164,445 1 9/27/2009 0.2624 22.396 171,350 1 9/28/2009 0.244 21.716 178,652 1 9/29/2009 0.2477 20.784 169,790 1 9/30/2009 0.2524 20.863 169,604 1 10/1/2009 0.2411 22.513 186,683 1 10/2/2009 0.2325 20.856 179,414 1 10/3/2009 0.1313 0.598 6,060 1 10/7/2009 0.0181 0.035 3,276 1 10/8/2009 0.103 2.601 27,845 1 10/9/2009 0.2059 18.142 175,119 1 10/10/2009 0.2194 20.806 190,259 1 10/11/2009 0.2098 19.8 188,683 1 10/12/2009 0.2499 24.099 192,840 1 10/13/2009 0.2572 24.66 191,558 1 10/14/2009 0.217 19.215 177,612 1 10/15/2009 0.2197 20.66 188,342 1 10/16/2009 0.2181 16.934 146,061 1 10/17/2009 0.2859 26.442 184,801 1 10/18/2009 0.2393 18.891 157,944 1 10/19/2009 0.2471 22.67 183,876 1 10/20/2009 0.2434 23.219 190,813
1 10/21/2009 0.2457 22.037 178,846 1 10/22/2009 0.2437 23.546 193,233 1 10/23/2009 0.2342 21.505 183,381 1 10/24/2009 0.2778 21.986 164,660 1 10/25/2009 0.261 23.63 180,733 1 10/26/2009 0.282 25.897 181,600 1 10/27/2009 0.2388 22.245 186,229 1 10/28/2009 0.2646 23.03 173,453 1 10/29/2009 0.2612 25.197 192,993 1 10/30/2009 0.2969 25.771 173,152 1 10/31/2009 0.275 20.524 155,484 1 11/1/2009 0.24 20.422 170,338 1 11/2/2009 0.2407 21.915 181,037 1 11/3/2009 0.2439 23.658 193,988 1 11/4/2009 0.2441 24.191 198,227 1 11/5/2009 0.2408 23.14 192,201 1 11/6/2009 0.239 23.424 195,972 1 11/7/2009 0.3008 26.77 179,558 1 11/8/2009 0.2839 27.824 196,035 1 11/9/2009 0.2309 22.044 191,074 1 11/10/2009 0.2232 21.629 193,791 1 11/11/2009 0.2322 21.276 183,505 1 11/12/2009 0.2323 21.877 188,405 1 11/13/2009 0.2235 21.093 188,761 1 11/14/2009 0.2407 19.833 169,629 1 11/15/2009 0.2398 21.074 178,440 1 11/16/2009 0.2416 22.088 182,498 1 11/17/2009 0.2444 22.727 185,298 1 11/18/2009 0.2675 25.5 190,795 1 11/19/2009 0.2644 24.905 187,826 1 11/20/2009 0.2558 25.076 196,091 1 11/21/2009 0.2614 25.879 198,002 1 11/22/2009 0.2866 25.585 180,892 1 11/23/2009 0.2669 25.978 194,669 1 11/24/2009 0.2643 25.777 195,036 1 11/25/2009 0.2674 26.216 196,066 1 11/26/2009 0.2421 22.007 181,702 1 11/27/2009 0.2024 19.373 191,302 1 11/28/2009 0.2262 19.388 176,586 1 11/29/2009 0.2126 21.011 197,657 1 11/30/2009 0.2246 21.342 191,357 1 12/1/2009 0.235 22.887 194,779 1 12/2/2009 0.2278 21.908 192,199 1 12/3/2009 0.2326 23.514 202,177 1 12/4/2009 0.2377 23.785 200,205 1 12/5/2009 0.2578 21.824 175,921 1 12/6/2009 0.2358 22.975 194,875
1 12/7/2009 0.2438 22.599 185,385 1 12/8/2009 0.2312 22.272 192,772 1 12/9/2009 0.2334 22.255 191,311 1 12/10/2009 0.2236 22.199 198,546 1 12/11/2009 0.2138 20.299 190,078 1 12/12/2009 0.2895 23.82 168,420 1 12/13/2009 0.2328 18.793 164,736 1 12/14/2009 0.217 20.137 184,394 1 12/15/2009 0.2241 21.809 194,862 1 12/16/2009 0.2255 21.731 192,781 1 12/17/2009 0.2121 20.822 196,522 1 12/18/2009 0.224 20.335 181,966 1 12/19/2009 0.2375 20.414 175,193 1 12/20/2009 0.2233 21.12 189,243 1 12/21/2009 0.2246 21.168 188,467 1 12/22/2009 0.2485 23.497 188,998 1 12/23/2009 0.2691 26.104 194,235 1 12/24/2009 0.2794 14.639 114,166 1 12/25/2009 0.0621 0.925 15,502 1 12/26/2009 0.2232 20.471 182,723 1 12/27/2009 0.2245 21.517 191,879 1 12/28/2009 0.217 20.65 190,240 1 12/29/2009 0.2149 21.123 196,616 1 12/30/2009 0.2244 21.379 190,648 1 12/31/2009 0.2446 22.456 183,231 1 1/1/2010 0.2255 21.167 187,682 1 1/2/2010 0.2472 21.08 175,457 1 1/3/2010 0.2242 21.432 191,270 1 1/4/2010 0.2109 20.432 193,792 1 1/5/2010 0.2211 21.426 193,808 1 1/6/2010 0.2386 18.882 165,099 1 1/7/2010 0.221 19.644 176,462 1 1/8/2010 0.2114 17.623 163,427 1 1/9/2010 0.2193 20.508 187,241 1 1/10/2010 0.2208 20.749 187,960 1 1/11/2010 0.2365 22.163 187,485 1 1/12/2010 0.2453 23.306 189,615 1 1/13/2010 0.297 28.967 194,558 1 1/14/2010 0.2842 27.53 193,543 1 1/15/2010 0.2856 28.326 198,336 1 1/16/2010 0.2991 25.997 177,113 1 1/17/2010 0.2743 25.113 182,520 1 1/18/2010 0.279 24.438 174,657 1 1/19/2010 0.2733 24.846 181,325 1 1/20/2010 0.2664 23.481 175,532 1 1/21/2010 0.274 24.503 177,916 1 1/22/2010 0.2829 26.412 186,815
1 1/23/2010 0.243 19.837 165,166 1 1/24/2010 0.2338 20.511 175,806 1 1/25/2010 0.2278 22.615 198,554 1 1/26/2010 0.2249 22.198 197,377 1 1/27/2010 0.2165 19.971 184,713 1 1/28/2010 0.2849 27.012 189,575 1 1/29/2010 0.2828 25.113 176,670 1 1/30/2010 0.2876 22.229 154,818 1 1/31/2010 0.2515 22.09 148,725 1 2/1/2010 0.2703 25.648 176,129 1 2/2/2010 0.2992 27.251 182,544 1 2/3/2010 0.275 27.686 201,338 1 2/4/2010 0.2721 27.138 199,542 1 2/5/2010 0.2478 23.519 190,047 1 2/6/2010 0.2328 20.58 182,706 1 2/7/2010 0.224 20.72 187,002 1 2/8/2010 0.2207 21.21 192,460 1 2/9/2010 0.2625 22.6 170,525 1 2/10/2010 0.2496 24.191 193,793 1 2/11/2010 0.2535 24.713 195,079 1 2/12/2010 0.2606 25.127 192,890 1 2/13/2010 0.2875 24.965 175,028 1 2/14/2010 0.2655 25.665 193,162 1 2/15/2010 0.2664 26.05 195,651 1 2/16/2010 0.2698 26.075 193,291 1 2/17/2010 0.2835 27.085 191,050 1 2/18/2010 0.2786 25.657 184,026 1 2/19/2010 0.2704 24.66 184,949 1 2/20/2010 0.105 0.977 10,224 1 3/21/2010 0.0201 0.083 7,244 1 3/22/2010 0.1987 7.368 66,506 1 3/23/2010 0.1843 16.561 181,217 1 3/24/2010 0.1821 18.207 199,792 1 3/25/2010 0.194 18.609 193,014 1 3/26/2010 0.2142 21.415 199,711 1 3/27/2010 0.1965 17.51 184,033 1 3/28/2010 0.1796 17.291 193,052 1 3/29/2010 0.1676 16.833 200,835 1 3/30/2010 0.1735 16.877 195,738 1 3/31/2010 0.1718 17.426 202,869 1 4/1/2010 0.1728 16.812 195,291 1 4/2/2010 0.1737 16.811 194,109 1 4/3/2010 0.1388 4.837 42,477 1 4/4/2010 0.1594 11.931 134,220 1 4/5/2010 0.1843 18.174 197,060 1 4/6/2010 0.1902 19.021 199,982 1 4/7/2010 0.1808 17.778 196,771
1 4/8/2010 0.1835 17.509 191,422 1 4/9/2010 0.1862 17.693 190,318 1 4/10/2010 0.228 19.36 174,659 1 4/11/2010 0.2044 19.104 188,655 1 4/12/2010 0.19 18.486 195,273 1 4/13/2010 0.2028 18.624 187,867 1 4/14/2010 0.2214 22.472 202,716 1 4/15/2010 0.2516 24.652 196,234 1 4/16/2010 0.2648 25.092 189,530 1 4/17/2010 0.2157 17.869 171,836 1 4/18/2010 0.2518 22.823 180,405 1 4/19/2010 0.259 23.98 185,074 1 4/20/2010 0.2578 24.199 187,740 1 4/21/2010 0.2654 25.315 190,730 1 4/22/2010 0.2631 25.777 195,921 1 4/23/2010 0.2647 25.062 189,340 1 4/24/2010 0.2699 21.67 162,829 1 4/25/2010 0.2553 23.076 180,663 1 4/26/2010 0.2689 25.284 187,997 1 4/27/2010 0.2529 24.266 192,112 1 4/28/2010 0.2435 24.092 197,625 1 4/29/2010 0.2153 20.848 193,827 1 4/30/2010 0.2161 21.827 202,101 1 5/1/2010 0.2627 23.583 181,531 1 5/2/2010 0.2089 21.664 207,393 1 5/3/2010 0.25 25.62 205,100 1 5/4/2010 0.2575 25.729 199,527 1 5/5/2010 0.2416 23.278 191,991 1 5/6/2010 0.2315 23.214 200,811 1 5/7/2010 0.2694 27.233 202,258 1 5/8/2010 0.2733 25.744 190,707 1 5/9/2010 0.2963 27.154 184,815 1 5/10/2010 0.2247 22.817 203,258 1 5/11/2010 0.2684 26.112 199,306 1 5/12/2010 0.2552 26.633 208,659 1 5/13/2010 0.2555 25.429 199,001 1 5/14/2010 0.2523 26.851 212,840 1 5/15/2010 0.25 23.115 188,487 1 5/16/2010 0.2388 24.284 203,473 1 5/17/2010 0.2402 24.465 203,525 1 5/18/2010 0.2502 25.344 202,638 1 5/19/2010 0.2603 26.042 199,883 1 5/20/2010 0.2413 24.035 199,037 1 5/21/2010 0.2449 24.816 202,660 1 5/22/2010 0.2607 23.546 184,935 1 5/23/2010 0.2441 26.169 214,435 1 5/24/2010 0.2526 26.032 205,992
1 5/25/2010 0.2518 25.772 204,656 1 5/26/2010 0.2464 24.331 196,980 1 5/27/2010 0.2496 25.909 207,626 1 5/28/2010 0.2353 22.017 185,447 1 5/29/2010 0.2644 23.718 180,639 1 5/30/2010 0.2595 23.648 182,486 1 5/31/2010 0.2593 25.021 191,134 1 6/1/2010 0.2641 27.579 207,957 1 6/2/2010 0.2546 27.177 213,484 1 6/3/2010 0.2455 23.534 189,871 1 6/6/2010 0.1503 11.423 95,868 1 6/7/2010 0.2485 25.341 203,099 1 6/8/2010 0.2484 26.455 212,998 1 6/9/2010 0.2488 25.949 208,623 1 6/10/2010 0.275 29.23 212,646 1 6/11/2010 0.2842 29.996 210,952 1 6/12/2010 0.2451 23.58 192,764 1 6/13/2010 0.2509 26.557 211,620 1 6/14/2010 0.24 25.088 209,081 1 6/15/2010 0.2763 28.133 203,272 1 6/16/2010 0.275 28.614 208,149 1 6/17/2010 0.266 27.845 209,373 1 6/18/2010 0.2703 28.041 207,522 1 6/19/2010 0.2934 27.652 189,156 1 6/20/2010 0.2922 30.563 209,187 1 6/21/2010 0.2885 30.561 211,832 1 6/22/2010 0.2844 28.471 199,716 1 6/23/2010 0.2758 27.324 197,144 1 6/24/2010 0.27 28.11 208,190 1 6/25/2010 0.2548 26.307 206,529 1 6/26/2010 0.2746 25.234 186,579 1 6/27/2010 0.259 26.651 205,554 1 6/28/2010 0.2641 27.109 205,362 1 6/29/2010 0.2663 27.287 205,077 1 6/30/2010 0.2635 27.147 206,030 1 7/1/2010 0.2596 26.917 207,354 1 7/2/2010 0.2391 24.64 206,221 1 7/3/2010 0.2528 22.579 183,539 1 7/4/2010 0.2474 25.063 202,228 1 7/5/2010 0.2432 24.872 204,498 1 7/6/2010 0.282 28.964 205,475 1 7/7/2010 0.2782 28.761 206,738 1 7/8/2010 0.279 29.277 209,878 1 7/9/2010 0.2808 29.026 206,709 1 7/10/2010 0.3021 28.47 188,958 1 7/11/2010 0.2915 29.614 203,030 1 7/12/2010 0.2835 28.878 203,711
1 7/13/2010 0.255 23.689 183,736 1 7/14/2010 0.2803 28.11 200,418 1 7/15/2010 0.2795 28.962 207,259 1 7/16/2010 0.2609 25.521 195,534 1 7/17/2010 0.28 25.098 180,246 1 7/18/2010 0.2653 25.887 194,004 1 7/19/2010 0.2645 26.17 197,810 1 7/20/2010 0.2578 24.882 192,669 1 7/21/2010 0.2676 26.094 194,914 1 7/22/2010 0.2393 22.75 188,229 1 7/23/2010 0.2103 20.808 197,760 1 7/24/2010 0.2269 18.969 175,143 1 7/25/2010 0.2214 21.322 194,389 1 7/26/2010 0.2356 24.52 207,912 1 7/27/2010 0.2179 20.532 187,760 1 7/28/2010 0.2498 22.324 176,755 1 7/29/2010 0.256 25.736 200,983 1 7/30/2010 0.2568 25.573 198,910 1 7/31/2010 0.311 29.639 191,293 1 8/1/2010 0.2794 28.948 207,134 1 8/2/2010 0.2789 28.839 206,544 1 8/3/2010 0.2832 30.087 212,590 1 8/4/2010 0.2669 28.321 212,274 1 8/5/2010 0.2843 28.321 199,293 1 8/6/2010 0.3009 30.435 201,985 1 8/7/2010 0.2324 21.7 188,963 1 8/8/2010 0.2139 21.677 203,123 1 8/9/2010 0.2075 18.951 182,041 1 8/10/2010 0.2226 22.429 201,886 1 8/11/2010 0.2355 19.065 162,431 1 8/12/2010 0.2611 25.678 195,833 1 8/13/2010 0.2678 23.715 180,693 1 8/14/2010 0.2618 20.084 155,737 1 8/15/2010 0.2574 23.858 182,175 1 8/16/2010 0.2257 17.033 148,284 1 8/17/2010 0.2456 22.964 186,131 1 8/18/2010 0.222 18.659 167,918 1 8/19/2010 0.2218 21.829 196,812 1 8/20/2010 0.2172 20.633 189,236 1 8/21/2010 0.2232 20.823 190,519 1 8/22/2010 0.2424 25.208 207,480 1 8/23/2010 0.2075 20.834 200,692 1 8/24/2010 0.2227 22.663 203,579 1 8/25/2010 0.2298 22.997 199,797 1 8/26/2010 0.2856 29.761 208,340 1 8/27/2010 0.2811 29.603 210,589 1 8/28/2010 0.2958 28.791 196,519
1 8/29/2010 0.2801 28.725 205,089 1 8/30/2010 0.2704 28.33 209,586 1 8/31/2010 0.2646 27.699 209,384 1 9/1/2010 0.2722 28.265 207,699 1 9/2/2010 0.2639 27.717 210,090 1 9/3/2010 0.2751 28.493 207,171 1 9/4/2010 0.229 20.452 181,873 1 9/5/2010 0.2362 18.821 166,586 1 9/6/2010 0.2136 19.503 180,968 1 9/7/2010 0.2181 22.5 206,398 1 9/8/2010 0.219 22.125 202,297 1 9/9/2010 0.2172 21.891 201,643 1 9/10/2010 0.2271 23.876 210,145 1 9/11/2010 0.2981 29.211 194,520 1 9/12/2010 0.3042 30.691 201,350 1 9/13/2010 0.2831 27.855 196,057 1 9/14/2010 0.2443 23.41 192,607 1 9/15/2010 0.2952 28.846 193,737 1 9/16/2010 0.2925 30.161 206,219 1 9/17/2010 0.2794 28.594 204,671 1 9/18/2010 0.2954 27.328 189,977 1 9/19/2010 0.2806 27.332 194,854 1 9/20/2010 0.2732 27.685 202,718 1 9/21/2010 0.2832 29.207 206,223 1 9/22/2010 0.2922 30.047 205,699 1 9/23/2010 0.2785 28.874 207,392 1 9/24/2010 0.2737 28.257 206,512 1 9/25/2010 0.294 27.525 188,132 1 9/26/2010 0.2893 27.046 186,762 1 9/27/2010 0.25 22.598 183,103 1 9/28/2010 0.2439 23.748 195,172 1 9/29/2010 0.2505 22.465 185,011 1 9/30/2010 0.2404 21.511 183,748 1 10/1/2010 0.2294 23.508 205,060 1 10/2/2010 0.2288 21.437 188,776 1 10/3/2010 0.2259 21.641 192,327 1 10/4/2010 0.2856 27.984 195,610 1 10/5/2010 0.2834 29.092 205,354 1 10/6/2010 0.2862 28.692 200,593 1 10/7/2010 0.2824 28.298 200,537 1 10/8/2010 0.2802 29.073 207,529 1 10/9/2010 0.292 27.867 190,877 1 10/10/2010 0.2769 28.683 207,054 1 10/11/2010 0.2459 24.448 199,999 1 10/12/2010 0.2136 20.95 195,506 1 10/13/2010 0.2154 21.868 202,773 1 10/14/2010 0.2196 21.985 200,529
1 10/15/2010 0.2204 21.505 195,926 1 10/16/2010 0.2917 27.461 188,175 1 10/17/2010 0.2618 23.545 183,396 1 10/18/2010 0.2446 25.17 205,989 1 10/19/2010 0.2188 20.826 191,391 1 10/20/2010 0.224 22.764 203,360 1 10/21/2010 0.2309 23.088 201,067 1 10/22/2010 0.2318 23.651 204,159 1 10/23/2010 0.235 21.697 186,421 1 10/24/2010 0.24 23.459 196,188 1 10/25/2010 0.2665 22.188 169,915 1 10/26/2010 0.2359 19.292 165,852 1 10/27/2010 0.2318 20.855 180,684 1 10/28/2010 0.2406 22.741 189,539 1 10/29/2010 0.2455 23.099 188,395 1 10/30/2010 0.2967 27.207 185,547 1 10/31/2010 0.2561 21.88 175,138 1 11/1/2010 0.2347 22.033 189,015 1 11/2/2010 0.277 26.873 194,078 1 11/3/2010 0.285 28.206 198,065 1 11/4/2010 0.3434 20.56 124,880 1 11/5/2010 0.241 21.14 172,918 1 11/6/2010 0.2381 21.488 184,218 1 11/7/2010 0.2274 20.738 183,946 1 11/8/2010 0.2383 23.397 196,588 1 11/9/2010 0.2398 22.365 187,077 1 11/10/2010 0.2361 21.876 186,398 1 11/11/2010 0.2535 19.769 154,191 1 11/12/2010 0.2768 27.724 200,178 1 11/13/2010 0.2898 24.397 171,689 1 11/14/2010 0.2768 26.116 188,681 1 11/15/2010 0.2703 25.702 189,586 1 11/16/2010 0.2877 21.164 149,409 1 11/17/2010 0.1694 5.503 55,507 1 11/18/2010 0.2278 20.195 177,298 1 11/19/2010 0.2353 21.078 180,626 1 11/20/2010 0.2288 20.684 183,259 1 11/21/2010 0.2258 21.767 193,751 1 11/22/2010 0.2905 27.242 188,178 1 11/23/2010 0.3445 13.456 80,656 1 11/24/2010 0.2676 8.61 65,010 1 11/25/2010 0.2434 18.831 157,963 1 11/26/2010 0.2239 19.222 170,019 1 11/27/2010 0.2383 21.741 183,949 1 11/28/2010 0.2398 20.67 173,911 1 11/29/2010 0.2239 21.048 187,884 1 11/30/2010 0.2323 22.708 194,543
1 12/1/2010 0.2416 24.592 203,637 1 12/2/2010 0.2433 22.339 184,162 1 12/3/2010 0.2371 24.03 202,866 1 12/4/2010 0.2331 23.785 204,109 1 12/5/2010 0.2478 22.067 184,403 1 12/6/2010 0.2543 26.265 206,875 1 12/7/2010 0.2663 25.039 187,245 1 12/8/2010 0.293 28.38 194,102 1 12/9/2010 0.2817 26.434 183,511 1 12/10/2010 0.2875 27.647 191,913 1 12/11/2010 0.256 22.286 177,015 1 12/12/2010 0.2492 24.616 197,914 1 12/13/2010 0.2475 24.822 200,824 1 12/14/2010 0.2296 19.921 171,815 1 12/15/2010 0.285 27.567 193,842 1 12/16/2010 0.2455 20.802 170,358 1 12/17/2010 0.2324 21.843 190,273 1 12/18/2010 0.2613 21.366 170,576 1 12/19/2010 0.2424 22.605 186,984 1 12/20/2010 0.2312 22.482 194,653 1 12/21/2010 0.23 21.245 185,043 1 12/22/2010 0.2856 25.944 181,207 1 12/23/2010 0.2844 27.014 190,152 1 12/24/2010 0.2795 24.808 177,347 1 12/25/2010 0.2407 19.198 164,425 1 12/26/2010 0.2235 21.217 190,308 1 12/27/2010 0.2313 20.666 179,642 1 12/28/2010 0.2375 21.652 182,546 1 12/29/2010 0.2645 25.449 190,736 1 12/30/2010 0.277 23.855 171,533 1 12/31/2010 0.3026 26.151 173,570 1 1/1/2011 0.2744 21.536 156,218 1 1/2/2011 0.2672 23.105 172,336 1 1/3/2011 0.2753 27 196,242 1 1/4/2011 0.2806 26.048 185,438 1 1/5/2011 0.2575 23.648 183,496 1 1/6/2011 0.2365 22.322 189,487 1 1/7/2011 0.2353 22.8 194,000 1 1/8/2011 0.2947 27.576 186,016 1 1/9/2011 0.3177 31.251 196,676 1 1/10/2011 0.3198 31.702 198,103 1 1/11/2011 0.3328 30.367 182,314 1 1/12/2011 0.3181 32.243 203,185 1 1/13/2011 0.2867 27.99 194,900 1 1/14/2011 0.2786 24.58 173,679 1 1/15/2011 0.327 30.171 187,100 1 1/16/2011 0.3086 30.303 196,273
1 1/17/2011 0.256 26.117 204,260 1 1/18/2011 0.2441 23.742 194,861 1 1/19/2011 0.2426 25.2 207,769 1 1/20/2011 0.2318 24.361 210,154 1 1/21/2011 0.2457 25.702 209,251 1 1/22/2011 0.2451 20.654 171,748 1 1/23/2011 0.2604 24.549 188,781 1 1/24/2011 0.227 21.365 189,609 1 1/25/2011 0.2405 24.748 205,811 1 1/26/2011 0.2602 25.822 198,511 1 1/27/2011 0.2867 25.786 179,872 1 1/28/2011 0.2598 26.364 202,981 1 1/29/2011 0.2598 22.796 176,057 1 1/30/2011 0.2678 24.491 184,992 1 1/31/2011 0.2594 25.458 196,838 1 2/1/2011 0.248 24.14 194,921 1 2/2/2011 0.256 24.036 186,626 1 2/3/2011 0.2923 6.742 50,057 1 2/7/2011 0.0326 0.119 6,602 1 2/8/2011 0.258 14.579 114,382 1 2/9/2011 0.2642 23.684 178,339 1 2/10/2011 0.2757 23.783 172,219 1 2/11/2011 0.2694 25.17 187,353 1 2/12/2011 0.2474 20.674 169,900 1 2/13/2011 0.262 22.12 171,222 1 2/14/2011 0.2597 20.397 158,752 1 2/15/2011 0.2999 22.772 152,588 1 2/16/2011 0.3121 18.583 119,114 1 2/17/2011 0.2927 16.883 117,158 1 2/18/2011 0.2941 19.895 140,530 1 2/19/2011 0.2715 23.768 176,567 1 2/20/2011 0.2998 29.001 191,782 1 2/21/2011 0.3223 29.897 187,466 1 2/22/2011 0.3201 31.697 197,027 1 2/23/2011 0.3143 32.46 206,620 1 2/24/2011 0.3074 31.299 203,713 1 2/25/2011 0.289 28.713 201,221 1 2/26/2011 0.366 0.42 2,297 1 3/11/2011 0.0187 0.06 6,279 1 3/12/2011 0.1579 10.754 90,201 1 3/13/2011 0.2883 29.341 203,713 1 3/14/2011 0.2793 29.347 210,151 1 3/15/2011 0.2819 29.423 208,766 1 3/16/2011 0.2881 29.67 205,998 1 3/17/2011 0.2551 25.673 201,221 1 3/18/2011 0.2693 27.686 205,444 1 3/19/2011 0.2478 24.946 202,814
1 3/20/2011 0.2425 25.152 207,659 1 3/21/2011 0.2491 25.753 206,897 1 3/22/2011 0.2512 25.491 202,952 1 3/23/2011 0.3294 32.169 197,040 1 3/24/2011 0.3284 28.585 171,004 1 3/25/2011 0.3242 33.688 207,489 1 3/26/2011 0.3377 35.203 208,540 1 3/27/2011 0.3066 28.918 191,333 1 3/28/2011 0.2696 25.198 186,586 1 3/29/2011 0.2587 23.697 184,101 1 3/30/2011 0.2491 24.75 199,260 1 3/31/2011 0.2541 24.441 192,974 1 4/1/2011 0.2089 18.767 156,848 1 4/2/2011 0.3048 26.807 177,289 1 4/3/2011 0.3077 30.696 198,991 1 4/4/2011 0.2943 28.607 191,457 1 4/5/2011 0.2855 25.756 177,800 1 4/6/2011 0.251 25.47 203,163 1 4/7/2011 0.2511 25.93 206,684 1 4/8/2011 0.2607 27.166 209,541 1 4/9/2011 0.2617 27.56 210,651 1 4/10/2011 0.3235 30.564 193,483 1 4/11/2011 0.3025 24.518 162,199 1 4/12/2011 0.3081 18.537 120,044 1 4/13/2011 0.3173 26.756 169,180 1 4/14/2011 0.2785 29.024 208,382 1 4/15/2011 0.3225 21.052 135,124 1 4/16/2011 0.3033 23.975 159,188 1 4/17/2011 0.3225 21.95 140,316 1 4/18/2011 0.2923 28.136 193,723 1 4/19/2011 0.2926 27.145 187,623 1 4/20/2011 0.2662 26.325 199,464 1 4/21/2011 0.3068 25.387 166,261 1 4/22/2011 0.3052 27.694 180,982 1 4/23/2011 0.1818 13.913 96,641 1 4/24/2011 0.2565 21.49 146,069 1 4/25/2011 0.3061 25.211 167,085 1 4/26/2011 0.2926 28.505 194,483 1 4/27/2011 0.3103 29.212 187,361 1 4/28/2011 0.3153 33.476 212,167 1 4/29/2011 0.3142 32 202,245 1 4/30/2011 0.3348 31.344 193,614 1 5/1/2011 0.3035 31.286 205,693 1 5/2/2011 0.3157 29.217 188,517 1 5/3/2011 0.2953 30.087 203,771 1 5/4/2011 0.2882 30.358 210,564 1 5/5/2011 0.3253 33.008 203,050
1 5/6/2011 0.3303 32.479 197,656 1 5/7/2011 0.335 31.433 190,510 1 5/8/2011 0.3232 32.219 197,485 1 5/9/2011 0.3485 33.531 190,878 1 5/10/2011 0.3502 36.017 205,098 1 5/11/2011 0.3198 30.162 187,118 1 5/12/2011 0.3328 34.496 206,860 1 5/13/2011 0.3 25.255 166,465 1 5/14/2011 0.2685 22.316 166,620 1 5/15/2011 0.2583 20.237 156,706 1 5/16/2011 0.2401 23.336 195,978 1 5/17/2011 0.245 20.526 167,790 1 5/18/2011 0.3041 29.025 188,581 1 5/19/2011 0.3013 28.953 192,586 1 5/20/2011 0.2849 24.003 174,209 1 5/21/2011 0.3387 19.749 119,185 1 5/22/2011 0.3179 26.546 167,128 1 5/23/2011 0.2817 19.462 138,655 1 5/24/2011 0.2652 12.27 94,238 1 5/25/2011 0.3277 14.403 88,399 1 5/26/2011 0.3134 11.742 75,516 1 5/27/2011 0.2824 18.587 132,303 1 5/28/2011 0.2844 17.518 128,124 1 5/29/2011 0.2762 21.743 158,702 1 5/30/2011 0.2673 25.753 194,432 1 5/31/2011 0.2588 27.233 212,989 1 6/1/2011 0.2501 25.855 209,164 1 6/2/2011 0.2549 26.463 207,806 1 6/3/2011 0.304 33.777 222,247 1 6/4/2011 0.2468 23.901 201,577 1 6/5/2011 0.2215 23.022 194,071 1 6/6/2011 0.2938 17.844 123,104 1 6/7/2011 0.2529 22.972 180,960 1 6/8/2011 0.289 28.385 192,998 1 6/9/2011 0.2639 26.331 198,818 1 6/10/2011 0.2426 22.745 185,207 1 6/11/2011 0.2614 21.274 165,344 1 6/12/2011 0.285 21.684 162,833 1 6/13/2011 0.2448 23.68 192,365 1 6/14/2011 0.2439 24.562 200,470 1 6/15/2011 0.2418 26.31 217,535 1 6/16/2011 0.3014 29.69 196,018 1 6/17/2011 0.3077 31.325 202,696 1 6/18/2011 0.2494 21.733 176,490 1 6/19/2011 0.2443 19.919 162,985 1 6/20/2011 0.2401 17.898 148,992 1 6/21/2011 0.2552 26.63 208,883
1 6/22/2011 0.3066 30.557 198,190 1 6/23/2011 0.2923 27.879 190,172 1 6/24/2011 0.2943 28.55 193,016 1 6/25/2011 0.2772 25.397 190,278 1 6/26/2011 0.2567 26.21 206,105 1 6/27/2011 0.2488 27.561 221,597 1 6/28/2011 0.2837 27.863 194,319 1 6/29/2011 0.2798 26.347 187,317 1 6/30/2011 0.2873 30.244 210,121 1 7/1/2011 0.2909 30.598 210,254 1 7/2/2011 0.2971 32.532 218,892 1 7/3/2011 0.2991 27.738 188,972 1 7/4/2011 0.2654 22.959 174,073 1 7/5/2011 0.2439 23.389 190,364 1 7/6/2011 0.2513 26.535 211,123 1 7/7/2011 0.2504 26.951 215,346 1 7/8/2011 0.2533 27.767 219,197 1 7/9/2011 0.239 24.282 205,122 1 7/10/2011 0.2417 26.837 222,145 1 7/11/2011 0.2405 26.62 221,393 1 7/12/2011 0.2691 28.291 209,935 1 7/13/2011 0.2866 31.379 218,780 1 7/14/2011 0.2852 30.975 217,155 1 7/15/2011 0.2978 32.598 218,739 1 7/16/2011 0.303 30.545 202,319 1 7/17/2011 0.2943 31.621 214,289 1 7/18/2011 0.2935 32.197 219,095 1 7/19/2011 0.2508 26.214 209,355 1 7/20/2011 0.2438 26.822 220,143 1 7/21/2011 0.2373 26.004 219,243 1 7/22/2011 0.2316 25.712 221,899 1 7/23/2011 0.2612 26.251 207,145 1 7/24/2011 0.2442 26.09 214,034 1 7/25/2011 0.2436 25.395 208,556 1 7/26/2011 0.2933 31.12 210,499 1 7/27/2011 0.3134 10.128 66,037 1 7/29/2011 0.089 2.118 20,420 1 7/30/2011 0.2457 19.261 158,945 1 7/31/2011 0.2636 25.89 198,165 1 8/1/2011 0.2543 27.118 215,177 1 8/2/2011 0.2931 30.617 209,369 1 8/3/2011 0.2884 30.395 210,149 1 8/4/2011 0.3111 34.653 222,817 1 8/5/2011 0.3055 33.391 218,715 1 8/6/2011 0.2476 24.84 204,489 1 8/7/2011 0.2378 25.849 217,528 1 8/8/2011 0.24 26.288 219,150
1 8/9/2011 0.2348 25.06 213,851 1 8/10/2011 0.2389 25.277 212,023 1 8/11/2011 0.2506 24.41 196,750 1 8/12/2011 0.2346 24.911 213,060 1 8/13/2011 0.2855 27.835 194,252 1 8/14/2011 0.2836 29.626 207,997 1 8/15/2011 0.2905 28.901 196,583 1 8/16/2011 0.2593 26.475 205,376 1 8/17/2011 0.242 26.494 218,994 1 8/18/2011 0.2462 26.264 213,453 1 8/19/2011 0.246 26.58 216,304 1 8/20/2011 0.3125 31.158 202,466 1 8/21/2011 0.2984 31.718 212,613 1 8/22/2011 0.3041 32.923 216,539 1 8/23/2011 0.3016 32.883 218,035 1 8/24/2011 0.3044 29.698 194,978 1 8/25/2011 0.297 30.825 207,837 1 8/26/2011 0.2936 29.115 198,020 1 8/27/2011 0.3214 30.116 190,500 1 8/28/2011 0.2824 27.764 198,603 1 8/29/2011 0.2455 25.407 207,435 1 8/30/2011 0.3029 31.871 210,147 1 8/31/2011 0.3024 33.783 223,442 1 9/1/2011 0.2995 28.429 188,503 1 9/2/2011 0.275 27.589 198,660 1 9/3/2011 0.2956 29.259 200,164 1 9/4/2011 0.294 30.918 210,336 1 9/5/2011 0.335 28.566 171,987 1 9/6/2011 0.3073 22.283 157,653 1 9/7/2011 0.2566 22.851 181,872 1 9/8/2011 0.2522 23.43 187,528 1 9/9/2011 0.2672 24.381 186,087 1 9/10/2011 0.2612 24.521 192,639 1 9/11/2011 0.2345 24.68 211,851 1 9/12/2011 0.2929 15.006 102,976 1 9/13/2011 0.3017 11.17 75,172 1 9/15/2011 0.0121 0.031 3,566 1 9/16/2011 0.2529 22.791 169,360 1 9/17/2011 0.2808 29.152 208,051 1 9/18/2011 0.2764 28.756 207,730 1 9/19/2011 0.2666 28.215 211,593 1 9/20/2011 0.269 28.224 209,369 1 9/21/2011 0.2565 27.649 215,740 1 9/22/2011 0.2566 27.998 218,256 1 9/23/2011 0.265 26.895 203,117 1 9/24/2011 0.2555 23.691 185,965 1 9/25/2011 0.2568 25.174 195,549
1 9/26/2011 0.2658 26.646 200,705

1 9/27/2011 0.2838 29.077 204,780

1 9/28/2011 0.2901 30.027 207,673

1 9/29/2011 0.3062 27.442 179,335

1 9/30/2011 0.2993 24.304 165,646

1 10/1/2011 0.3272 28.377 172,370

1 10/2/2011 0.332 27.139 167,584

1 10/3/2011 0.299 27.784 185,830

1 10/4/2011 0.2973 26.108 185,301

1 10/5/2011 0.2848 28.83 202,563

1 10/6/2011 0.2912 29.672 203,710

1 10/7/2011 0.2583 20.305 158,190

1 12/1/2011 0.0344 0.276 12,257

1 12/2/2011 0.1488 2.584 19,245

1 12/3/2011 0.2449 7.913 67,100

1 12/4/2011 0.0213 0.064 5,278

1 12/5/2011 0.2395 3.643 27,954

1 12/6/2011 0.1552 11.391 97,526

1 12/7/2011 0.1832 6.469 54,040

1 12/8/2011 0.0355 0.24 12,053

1 12/9/2011 0.1425 4.276 35,345

1 12/10/2011 0.2094 18.036 166,221

1 12/11/2011 0.2645 26.706 201,593

1 12/12/2011 0.3437 27.04 159,061

1 12/13/2011 0.3433 21.816 130,345

1 12/14/2011 0.3019 21.065 140,785

1 12/15/2011 0.2904 22.341 156,132

1 12/16/2011 0.2785 25.628 184,586

1 12/17/2011 0.3318 25.227 154,770

1 12/18/2011 0.2967 26.504 178,319

1 12/19/2011 0.3098 25.612 164,932

1 12/20/2011 0.2955 26.485 178,182

1 12/21/2011 0.2774 23.53 176,338

1 12/22/2011 0.2623 19.466 151,302

1 12/23/2011 0.2683 20.937 163,070

1 12/24/2011 0.2581 18.565 145,510

1 12/25/2011 0.2963 17.234 117,109

1 12/26/2011 0.2589 19.485 156,074

1 12/27/2011 0.2525 18.381 147,026

1 12/28/2011 0.2361 18.315 157,262

1 12/29/2011 0.267 19.695 146,980

1 12/30/2011 0.2305 17.172 148,630

1 12/31/2011 0.2204 15.742 146,090

Max (tpd) --> 36.017

Max (lb/hr) --> 3001.4

Note: Dates with no operation/emissions not shown
 Unit ID Date

 Avg. NOx Rate 

(lb/MMBtu)

 NOx 

(tons)

 Heat Input 

(MMBtu)

2 1/1/2009 0.0261 0.091 5,640 2 1/2/2009 0.2909 18.42 127,323 2 1/3/2009 0.2318 13.585 119,933 2 1/8/2009 0.0775 1.118 12,624 2 1/9/2009 0.2739 23.517 171,068 2 1/10/2009 0.2507 20.168 162,382 2 1/11/2009 0.2739 22.223 163,644 2 1/12/2009 0.2975 29.043 193,510 2 1/13/2009 0.2893 26.767 181,728 2 1/14/2009 0.3188 32.754 205,116 2 1/15/2009 0.31 28.395 180,371 2 1/16/2009 0.3048 27.868 176,283 2 1/17/2009 0.2602 25.026 191,525 2 1/18/2009 0.2593 23.665 180,663 2 1/19/2009 0.3101 30.405 194,800 2 1/20/2009 0.3551 35.611 201,033 2 1/21/2009 0.3343 34.302 205,302 2 1/22/2009 0.3221 32.896 204,164 2 1/23/2009 0.3216 31.966 198,290 2 1/24/2009 0.2958 27.507 183,605 2 1/25/2009 0.3155 28.282 178,578 2 1/26/2009 0.2993 28.875 192,705 2 1/27/2009 0.3009 25.29 166,495 2 1/28/2009 0.2567 21.379 167,368 2 1/29/2009 0.2704 22.598 164,099 2 1/30/2009 0.2523 18.045 142,425 2 1/31/2009 0.2298 15.086 129,124 2 2/1/2009 0.2836 22.647 158,168 2 2/2/2009 0.3019 25.355 166,649 2 2/3/2009 0.2946 28.553 193,402 2 2/4/2009 0.2917 27.911 191,143 2 2/5/2009 0.278 24.888 178,569 2 2/6/2009 0.2869 24.119 169,541 2 3/10/2009 0.0153 0.055 5,142 2 3/11/2009 0.0995 2.116 27,663 2 3/12/2009 0.2269 11.877 105,805 2 3/13/2009 0.224 12.707 116,628 2 3/14/2009 0.278 24.624 174,313 2 3/15/2009 0.2862 28.461 198,920 2 3/16/2009 0.2786 23.489 162,301 2 3/17/2009 0.2813 28.246 200,711 2 3/18/2009 0.2543 24.712 192,237 2 3/19/2009 0.2388 22.403 186,664 2 3/20/2009 0.2793 26.931 192,324 2 3/21/2009 0.2939 28.949 196,639
2 3/22/2009 0.3368 25.926 160,754 2 3/23/2009 0.2891 27.445 185,615 2 3/24/2009 0.28 26.217 183,347 2 3/25/2009 0.2845 26.316 183,498 2 3/26/2009 0.2292 17.558 154,379 2 3/27/2009 0.2301 19.644 169,547 2 3/28/2009 0.2328 20.618 174,851 2 3/29/2009 0.2912 22.947 161,137 2 3/30/2009 0.2319 18.375 157,407 2 3/31/2009 0.2632 21.662 165,761 2 4/1/2009 0.2305 19.969 173,539 2 4/2/2009 0.2834 26.598 185,888 2 4/3/2009 0.2948 25.478 178,791 2 4/4/2009 0.2834 26.519 187,224 2 4/5/2009 0.2995 22.771 158,096 2 4/6/2009 0.2886 24.795 170,003 2 4/7/2009 0.2774 22.94 165,933 2 4/8/2009 0.2798 27.927 199,584 2 4/9/2009 0.2935 28.35 192,328 2 4/10/2009 0.2943 29.188 197,666 2 4/11/2009 0.2406 21.521 178,271 2 4/12/2009 0.2444 20.202 170,894 2 4/13/2009 0.2386 23.46 196,569 2 4/14/2009 0.235 21.614 183,468 2 4/15/2009 0.2654 25.425 189,209 2 4/16/2009 0.2962 29.264 197,585 2 4/17/2009 0.3001 29.528 196,034 2 4/18/2009 0.2917 26.649 181,591 2 4/19/2009 0.2607 20.281 163,877 2 4/20/2009 0.2765 20.982 151,331 2 4/21/2009 0.2872 18.688 134,224 2 4/22/2009 0.2946 19.749 140,507 2 4/23/2009 0.2872 20.909 147,977 2 4/24/2009 0.2655 21.91 165,115 2 4/25/2009 0.2919 26.843 185,377 2 4/26/2009 0.3163 26.158 174,199 2 4/27/2009 0.2764 27.239 196,737 2 4/28/2009 0.2998 26.418 179,218 2 4/29/2009 0.2612 25.324 193,188 2 4/30/2009 0.2669 24.279 182,477 2 5/1/2009 0.2713 26.87 197,305 2 5/2/2009 0.2759 25.246 182,506 2 5/3/2009 0.3023 24.906 169,518 2 5/4/2009 0.2453 24.406 199,418 2 5/5/2009 0.2289 22.984 200,712 2 5/6/2009 0.2312 24.118 208,634 2 5/7/2009 0.2237 21.628 192,131
2 5/8/2009 0.2238 20.322 184,264 2 5/10/2009 0.0475 0.316 6,652 2 5/13/2009 0.0345 0.095 5,089 2 5/14/2009 0.2212 15.754 144,287 2 5/15/2009 0.2099 19.947 188,515 2 5/16/2009 0.2342 22.483 192,186 2 5/17/2009 0.2663 17.789 143,453 2 5/18/2009 0.3109 16.009 119,022 2 5/19/2009 0.3356 23.757 148,024 2 5/20/2009 0.3431 27.769 172,398 2 5/21/2009 0.2713 25.308 187,292 2 5/22/2009 0.271 25.287 186,142 2 5/23/2009 0.2786 24.6 177,111 2 5/24/2009 0.2987 22.044 149,976 2 5/25/2009 0.3122 28.598 182,290 2 5/26/2009 0.2694 25.161 187,188 2 5/27/2009 0.2783 27.584 198,031 2 5/28/2009 0.2693 25.369 188,054 2 5/29/2009 0.2698 26.267 194,221 2 5/30/2009 0.2825 23.995 174,613 2 5/31/2009 0.3342 28.272 172,557 2 6/1/2009 0.266 23.483 178,127 2 6/2/2009 0.2611 25.715 196,721 2 6/3/2009 0.2533 22.715 179,806 2 6/4/2009 0.271 20.851 158,037 2 6/5/2009 0.2674 22.602 171,796 2 6/6/2009 0.2957 22.743 162,591 2 6/7/2009 0.2636 21.407 170,189 2 6/8/2009 0.2481 22.267 181,947 2 6/9/2009 0.2329 22.017 189,044 2 6/10/2009 0.2265 21.733 191,665 2 6/11/2009 0.2374 18.931 162,381 2 6/12/2009 0.2573 19.877 155,848 2 6/13/2009 0.2581 21.896 170,331 2 6/14/2009 0.2747 19.471 147,429 2 6/15/2009 0.2846 26.277 182,258 2 6/16/2009 0.2907 25.986 178,046 2 6/17/2009 0.3072 29.88 194,039 2 6/18/2009 0.2996 28.044 186,931 2 6/21/2009 0.1197 4.959 46,582 2 6/22/2009 0.2236 22.416 200,395 2 6/23/2009 0.2248 22.535 200,333 2 6/24/2009 0.2741 27.504 199,998 2 6/25/2009 0.3138 31.309 199,188 2 6/26/2009 0.2556 23.784 184,452 2 6/27/2009 0.2583 24.851 162,343 2 6/28/2009 0.2903 28.691 197,646
2 6/29/2009 0.263 22.635 171,126 2 6/30/2009 0.2483 19.334 151,681 2 7/1/2009 0.2656 23.073 169,900 2 7/2/2009 0.2575 23.22 177,500 2 7/3/2009 0.2675 22.222 166,394 2 7/4/2009 0.273 24.728 179,753 2 7/5/2009 0.2543 20.745 159,592 2 7/6/2009 0.2562 23.265 178,252 2 7/7/2009 0.2721 26.092 190,572 2 7/8/2009 0.3048 29.026 189,384 2 7/9/2009 0.3118 30.494 195,328 2 7/10/2009 0.3191 32.415 202,918 2 7/11/2009 0.3213 30.604 188,437 2 7/12/2009 0.3187 28.733 176,910 2 7/13/2009 0.3282 32.729 199,236 2 7/14/2009 0.2708 25.07 184,893 2 7/15/2009 0.2813 26.429 186,932 2 7/16/2009 0.2845 27.408 191,498 2 7/17/2009 0.2359 19.018 162,426 2 7/18/2009 0.2425 20.145 164,577 2 7/19/2009 0.2653 19.508 155,821 2 7/20/2009 0.236 21.72 184,119 2 7/21/2009 0.22 20.124 183,440 2 7/22/2009 0.274 24.392 173,242 2 7/23/2009 0.3088 30.97 200,132 2 7/24/2009 0.286 26.564 184,917 2 7/25/2009 0.2697 24.839 184,894 2 7/26/2009 0.2895 19.872 142,800 2 7/27/2009 0.2409 19.605 163,263 2 7/28/2009 0.246 20.557 164,855 2 7/29/2009 0.2853 23.79 166,403 2 7/30/2009 0.291 24.573 167,059 2 7/31/2009 0.3055 31.279 204,690 2 8/1/2009 0.2828 25.528 179,649 2 8/2/2009 0.2508 19.842 161,155 2 8/3/2009 0.245 24.245 198,288 2 8/4/2009 0.2352 23.658 201,238 2 8/5/2009 0.2216 20.975 188,904 2 8/6/2009 0.2191 20.001 182,055 2 8/7/2009 0.2285 22.092 192,540 2 8/8/2009 0.2277 23.152 203,064 2 8/9/2009 0.2445 22.201 182,293 2 8/10/2009 0.2472 25.346 204,973 2 8/11/2009 0.2256 22.964 203,497 2 8/12/2009 0.2961 29.01 192,204 2 8/13/2009 0.2277 21.492 188,631 2 8/14/2009 0.2335 23.534 201,382
2 8/15/2009 0.2299 21.944 191,080 2 8/16/2009 0.2366 20.663 179,765 2 8/17/2009 0.2187 21.87 200,005 2 8/18/2009 0.2978 28.635 191,809 2 8/19/2009 0.2924 27.803 189,161 2 8/20/2009 0.2888 26.9 185,739 2 8/21/2009 0.2437 21.693 178,823 2 8/22/2009 0.2332 21.642 186,341 2 8/23/2009 0.2612 19.258 159,475 2 8/24/2009 0.2303 20.179 176,997 2 8/25/2009 0.3071 28.576 186,272 2 8/26/2009 0.2597 24.244 186,079 2 8/27/2009 0.3139 30.067 190,691 2 8/28/2009 0.3126 31.529 201,669 2 8/29/2009 0.3215 31.495 195,088 2 8/30/2009 0.3267 27.579 169,222 2 8/31/2009 0.3178 29.264 183,648 2 9/1/2009 0.3099 27.268 175,096 2 9/2/2009 0.3059 28.038 181,422 2 9/3/2009 0.3375 32.789 193,031 2 9/4/2009 0.3618 36.842 203,599 2 9/5/2009 0.3384 33.023 194,479 2 9/6/2009 0.3513 29.848 169,190 2 9/7/2009 0.3366 29.943 172,742 2 9/8/2009 0.3393 32.53 188,604 2 9/9/2009 0.3634 36.179 198,949 2 9/10/2009 0.3643 36.752 201,548 2 9/11/2009 0.3347 32.879 196,345 2 9/12/2009 0.3207 30.37 188,358 2 9/13/2009 0.3158 25.212 157,901 2 9/14/2009 0.3433 32.589 189,217 2 9/15/2009 0.3474 35.384 203,659 2 9/16/2009 0.3135 30.582 195,154 2 9/17/2009 0.278 28.479 205,009 2 9/18/2009 0.2556 26.107 204,203 2 9/19/2009 0.2477 24.919 200,940 2 9/20/2009 0.24 20.354 179,055 2 9/21/2009 0.2965 29.334 197,473 2 9/22/2009 0.2865 24.363 169,762 2 9/23/2009 0.3193 31.254 194,834 2 9/24/2009 0.2957 29.356 198,015 2 9/25/2009 0.3429 32.891 190,096 2 9/26/2009 0.2707 24.502 181,353 2 9/27/2009 0.3319 29.016 173,398 2 9/28/2009 0.3338 31.934 190,619 2 9/29/2009 0.3264 30.063 181,892 2 9/30/2009 0.3341 31.157 185,729
2 10/1/2009 0.337 33.527 198,295 2 10/2/2009 0.3071 29.155 189,928 2 10/3/2009 0.3392 34.386 202,442 2 10/4/2009 0.3227 28.311 174,891 2 10/5/2009 0.3143 30.416 192,620 2 10/6/2009 0.2634 26.18 198,787 2 10/7/2009 0.2722 27.582 202,631 2 10/8/2009 0.2904 30.102 207,317 2 10/9/2009 0.3225 32.316 200,214 2 10/10/2009 0.3102 31.064 200,417 2 10/11/2009 0.2866 25.449 179,828 2 10/12/2009 0.3364 34.524 205,186 2 10/13/2009 0.3295 33.467 202,938 2 10/14/2009 0.2984 28.168 188,546 2 10/15/2009 0.3007 30.132 200,178 2 10/16/2009 0.2585 24.37 189,105 2 10/17/2009 0.2405 23.248 193,325 2 10/18/2009 0.2327 19.852 172,447 2 10/19/2009 0.2583 21.54 176,853 2 10/20/2009 0.3089 30.936 200,414 2 10/21/2009 0.331 31.573 189,942 2 10/22/2009 0.3215 32.427 201,492 2 10/23/2009 0.3254 31.777 195,004 2 10/24/2009 0.3237 30.929 190,847 2 10/25/2009 0.3014 24.939 173,417 2 10/26/2009 0.2904 28.241 193,625 2 10/27/2009 0.2895 27.138 187,182 2 10/28/2009 0.2762 25.385 183,112 2 10/29/2009 0.3016 24.228 149,851 2 10/30/2009 0.276 24.937 179,381 2 10/31/2009 0.3163 29.015 183,175 2 11/1/2009 0.3 24.027 160,652 2 11/2/2009 0.2995 28.419 189,147 2 11/3/2009 0.2779 26.764 191,721 2 11/4/2009 0.3273 32.177 196,367 2 11/5/2009 0.3008 28.209 187,854 2 11/6/2009 0.2773 26.957 194,014 2 11/7/2009 0.239 24.316 203,639 2 11/8/2009 0.2415 20.624 179,056 2 11/9/2009 0.2334 22.196 191,275 2 11/10/2009 0.274 25.86 188,887 2 11/11/2009 0.2899 25.937 177,459 2 11/12/2009 0.2822 26.204 185,163 2 11/13/2009 0.3457 33.076 191,030 2 11/14/2009 0.308 26.008 167,792 2 11/15/2009 0.2969 22.156 154,028 2 11/16/2009 0.303 28.564 186,117
2 11/17/2009 0.2463 21.708 176,444 2 11/18/2009 0.2287 20.859 182,735 2 11/19/2009 0.257 23.372 182,126 2 11/20/2009 0.3081 29.036 188,264 2 11/21/2009 0.3112 31.302 200,799 2 11/22/2009 0.2751 24.259 182,490 2 11/23/2009 0.2678 25.736 190,654 2 11/24/2009 0.283 23.623 176,602 2 11/25/2009 0.2725 27.097 198,807 2 11/26/2009 0.2737 25.751 186,850 2 11/27/2009 0.2691 24.821 182,788 2 11/28/2009 0.2781 27.448 197,275 2 11/29/2009 0.2995 26.176 176,650 2 11/30/2009 0.2893 27.559 188,729 2 12/1/2009 0.263 25.754 195,438 2 12/2/2009 0.2288 22.158 193,764 2 12/3/2009 0.2292 22.967 200,612 2 12/4/2009 0.2789 28.516 204,516 2 12/5/2009 0.3279 33.185 202,289 2 12/6/2009 0.3362 30.336 181,762 2 12/7/2009 0.2911 23.975 163,918 2 12/8/2009 0.3119 13.806 89,495 2 12/12/2009 0.1133 2.242 17,812 2 12/13/2009 0.3005 9.515 64,247 2 12/15/2009 0.0715 0.495 7,631 2 12/16/2009 0.3058 13.259 87,248 2 12/17/2009 0.2774 24.817 179,647 2 12/18/2009 0.2795 23.795 170,154 2 12/19/2009 0.2925 26.9 183,803 2 12/20/2009 0.3163 26.804 169,918 2 12/21/2009 0.3035 27.058 176,287 2 12/22/2009 0.3173 29.349 183,895 2 12/23/2009 0.3085 28.641 184,277 2 12/24/2009 0.3026 23.362 151,431 2 12/25/2009 0.2614 20.029 138,839 2 12/26/2009 0.2884 26.201 181,269 2 12/27/2009 0.3037 25.434 172,918 2 12/28/2009 0.2686 25.538 190,783 2 12/29/2009 0.2632 24.618 187,058 2 12/30/2009 0.2595 24.177 185,973 2 12/31/2009 0.2488 20.416 164,415 2 1/1/2010 0.2521 21.984 175,045 2 1/2/2010 0.2541 25.184 198,140 2 1/3/2010 0.2991 26.232 177,269 2 1/4/2010 0.3008 29.406 195,488 2 1/5/2010 0.3034 29.976 197,637 2 1/6/2010 0.2983 23.951 161,388
2 1/7/2010 0.2696 23.191 171,608 2 1/8/2010 0.267 27.171 203,605 2 1/9/2010 0.259 24.768 190,624 2 1/10/2010 0.28 23.223 174,232 2 1/11/2010 0.2847 26.609 186,798 2 1/12/2010 0.2849 12.514 87,786 2 1/13/2010 0.0186 0.024 2,204 2 1/14/2010 0.2851 23.986 147,505 2 1/15/2010 0.3113 31.803 204,470 2 1/16/2010 0.2878 28.004 194,510 2 1/17/2010 0.3285 26.02 158,205 2 1/18/2010 0.3239 28.176 173,134 2 1/19/2010 0.3114 27.115 171,179 2 1/20/2010 0.2508 20.844 166,137 2 1/21/2010 0.2464 21.427 175,286 2 1/22/2010 0.2232 19.947 179,534 2 1/23/2010 0.2739 23.923 172,387 2 1/24/2010 0.2533 19.566 159,630 2 1/25/2010 0.23 21.699 188,704 2 1/26/2010 0.2524 24.197 190,859 2 1/27/2010 0.2611 22.576 171,951 2 1/28/2010 0.3136 26.415 167,979 2 1/29/2010 0.274 23.494 171,604 2 1/30/2010 0.2962 26.224 177,073 2 1/31/2010 0.2905 22.917 157,574 2 2/1/2010 0.3446 29.991 172,425 2 2/2/2010 0.3399 27.803 162,876 2 2/3/2010 0.3475 32.646 187,540 2 2/4/2010 0.366 34.608 189,024 2 2/5/2010 0.3118 26.923 172,586 2 2/6/2010 0.3215 31.463 195,644 2 2/7/2010 0.2856 23.847 171,558 2 2/8/2010 0.2714 26.051 191,688 2 2/9/2010 0.2904 22.913 161,523 2 2/10/2010 0.274 25.86 188,792 2 2/11/2010 0.3164 29.867 187,058 2 2/12/2010 0.3386 32.637 192,683 2 2/13/2010 0.3157 29.228 184,452 2 2/14/2010 0.3246 27.164 168,702 2 2/15/2010 0.3329 33.142 199,022 2 2/16/2010 0.3281 30.89 187,869 2 2/17/2010 0.3458 32.105 184,900 2 2/18/2010 0.3348 30.135 178,528 2 2/19/2010 0.2944 26.965 181,186 2 2/20/2010 0.2753 26.523 192,646 2 2/21/2010 0.2781 22.728 167,967 2 2/22/2010 0.3088 26.762 171,561
2 2/23/2010 0.2846 25.187 176,544 2 2/24/2010 0.2874 25.997 180,771 2 2/25/2010 0.2931 26.44 180,272 2 2/26/2010 0.2967 27.438 184,193 2 2/27/2010 0.289 27.136 187,376 2 2/28/2010 0.3167 25.16 164,061 2 3/1/2010 0.299 22.904 157,411 2 3/2/2010 0.314 30.757 195,772 2 3/3/2010 0.3001 26.325 174,761 2 3/4/2010 0.368 32.709 176,014 2 3/5/2010 0.375 34.798 184,149 2 3/6/2010 0.3696 34.14 183,305 2 3/7/2010 0.3727 34.272 182,926 2 3/8/2010 0.3644 35.184 192,521 2 3/9/2010 0.3495 33.952 193,746 2 3/10/2010 0.3603 36.566 202,397 2 3/11/2010 0.3514 34.602 196,089 2 3/12/2010 0.3642 34.605 189,238 2 3/13/2010 0.3768 35.512 187,053 2 3/14/2010 0.3635 31.076 171,359 2 3/15/2010 0.3218 29.648 183,534 2 3/16/2010 0.3101 28.696 184,617 2 3/17/2010 0.3079 29.313 190,207 2 3/18/2010 0.3283 32.476 197,363 2 3/19/2010 0.3117 30.682 196,351 2 3/20/2010 0.302 26.599 176,023 2 3/21/2010 0.3317 29.287 179,193 2 3/22/2010 0.3054 28.434 185,702 2 3/23/2010 0.2925 24.976 170,091 2 3/24/2010 0.3304 32.319 193,083 2 3/25/2010 0.3379 32.485 189,060 2 3/26/2010 0.3578 35.405 197,427 2 3/27/2010 0.373 37.857 203,107 2 3/28/2010 0.3594 31.488 175,683 2 3/29/2010 0.3452 33.909 196,164 2 3/30/2010 0.3747 36.331 193,829 2 3/31/2010 0.335 32.242 191,293 2 4/1/2010 0.3479 33.54 191,858 2 4/2/2010 0.3054 25.083 164,350 2 4/21/2010 0.0104 0.009 1,248 2 4/22/2010 0.1424 5.172 47,139 2 4/23/2010 0.2579 23.589 182,271 2 4/24/2010 0.2622 23.872 182,387 2 4/25/2010 0.3231 23.56 154,666 2 4/26/2010 0.306 29.095 190,300 2 4/27/2010 0.3617 33.912 187,710 2 4/28/2010 0.3753 34.644 183,603
2 4/29/2010 0.3645 32.248 176,285 2 4/30/2010 0.3723 36.861 197,950 2 5/1/2010 0.367 37.547 204,578 2 5/2/2010 0.3828 35.725 187,772 2 5/3/2010 0.3332 33.052 198,238 2 5/4/2010 0.3265 30.152 183,692 2 5/5/2010 0.2584 22.273 172,845 2 5/6/2010 0.2874 26.371 183,523 2 5/7/2010 0.3903 40.035 205,043 2 5/8/2010 0.4003 39.405 198,799 2 5/9/2010 0.4328 35.521 170,135 2 5/10/2010 0.3978 39.861 200,328 2 5/11/2010 0.3931 40.6 206,565 2 5/12/2010 0.388 40.227 207,331 2 5/13/2010 0.4002 41.74 208,549 2 5/14/2010 0.4039 42.329 209,606 2 5/15/2010 0.4003 41.404 206,779 2 5/16/2010 0.3858 34.968 181,387 2 5/17/2010 0.359 35.109 194,245 2 5/18/2010 0.3375 32.519 191,826 2 5/19/2010 0.3555 32.992 184,593 2 5/20/2010 0.3539 23.745 141,069 2 5/21/2010 0.266 24.74 185,979 2 5/22/2010 0.2758 24.289 177,848 2 5/23/2010 0.3413 30.208 175,857 2 5/24/2010 0.3102 28.437 182,297 2 5/25/2010 0.3129 28.355 181,153 2 5/26/2010 0.309 26.721 173,220 2 5/27/2010 0.307 29.872 193,938 2 5/28/2010 0.2945 25.802 172,520 2 5/29/2010 0.2803 24.142 174,728 2 5/30/2010 0.3133 24.148 162,494 2 5/31/2010 0.3765 34.825 186,096 2 6/1/2010 0.3768 37.764 199,921 2 6/2/2010 0.373 38.857 208,101 2 6/3/2010 0.3377 33.463 197,657 2 6/4/2010 0.3548 37.292 210,092 2 6/5/2010 0.3643 37.882 207,525 2 6/6/2010 0.3784 36.735 190,765 2 6/7/2010 0.3485 33.179 186,705 2 6/8/2010 0.392 40.222 205,035 2 6/9/2010 0.3822 38.475 200,887 2 6/10/2010 0.3068 30.981 200,751 2 6/11/2010 0.2801 28.255 201,667 2 6/12/2010 0.2662 26.587 199,525 2 6/13/2010 0.2632 23.522 178,654 2 6/14/2010 0.3279 31.576 192,221
2 6/15/2010 0.4133 41.545 200,266 2 6/16/2010 0.4036 41.298 204,473 2 6/17/2010 0.3988 40.592 203,371 2 6/18/2010 0.3715 37.442 201,230 2 6/19/2010 0.3702 37.421 201,635 2 6/20/2010 0.3685 34.684 181,864 2 6/21/2010 0.3697 38.138 206,264 2 6/22/2010 0.3138 29.065 182,869 2 6/23/2010 0.3401 32.751 191,169 2 6/24/2010 0.354 35.952 203,054 2 6/25/2010 0.362 36.045 198,253 2 6/26/2010 0.3605 35.497 195,790 2 6/27/2010 0.358 31.223 173,774 2 6/28/2010 0.3546 35.884 202,169 2 6/29/2010 0.346 33.691 193,606 2 6/30/2010 0.3413 33.914 197,055 2 7/1/2010 0.3533 36.572 206,953 2 7/2/2010 0.3557 36.588 205,608 2 7/3/2010 0.3384 32.9 192,412 2 7/4/2010 0.3551 14.261 80,752 2 7/6/2010 0.1452 5.573 49,282 2 7/7/2010 0.2467 17.715 140,569 2 7/10/2010 0.108 3.371 35,086 2 7/11/2010 0.235 22.931 194,447 2 7/12/2010 0.2325 22.063 188,786 2 7/13/2010 0.2195 19.448 175,188 2 7/14/2010 0.2428 23.049 188,608 2 7/15/2010 0.3083 30.652 198,278 2 7/16/2010 0.326 30.626 187,183 2 7/17/2010 0.3212 29.628 182,888 2 7/18/2010 0.3038 25.898 168,068 2 7/19/2010 0.2688 25.087 186,290 2 7/20/2010 0.279 25.228 179,195 2 7/21/2010 0.2851 26.858 187,148 2 7/22/2010 0.2703 25.008 182,559 2 7/23/2010 0.2768 26.549 190,507 2 7/24/2010 0.2814 26.978 189,979 2 7/25/2010 0.3176 27.256 170,903 2 7/26/2010 0.3116 31.933 204,884 2 7/27/2010 0.2922 26.244 177,889 2 7/28/2010 0.3106 26.435 168,005 2 7/29/2010 0.3374 32.237 190,341 2 7/30/2010 0.3345 32.409 192,843 2 7/31/2010 0.3568 35.895 200,721 2 8/1/2010 0.3287 30 181,805 2 8/2/2010 0.3021 27.242 165,631 2 8/3/2010 0.0843 3.155 34,642
2 8/4/2010 0.2788 23.472 165,844 2 8/5/2010 0.288 24.484 169,998 2 8/6/2010 0.3184 30.386 188,776 2 8/7/2010 0.3336 33.039 197,750 2 8/8/2010 0.3155 29.241 181,162 2 8/9/2010 0.2735 24.581 173,678 2 8/10/2010 0.2764 26.072 187,917 2 8/11/2010 0.292 21.984 148,836 2 8/12/2010 0.2346 21.782 184,976 2 8/13/2010 0.2312 21.354 183,762 2 8/14/2010 0.2738 25.002 180,481 2 8/15/2010 0.3087 28.549 181,951 2 8/16/2010 0.268 23.016 166,550 2 8/17/2010 0.2336 19.862 168,430 2 8/18/2010 0.2405 20.847 170,012 2 8/19/2010 0.2278 21.202 184,826 2 8/20/2010 0.2172 19.364 177,073 2 8/21/2010 0.2313 20.219 175,695 2 8/22/2010 0.3024 22.011 151,000 2 8/23/2010 0.3017 23.994 162,738 2 8/24/2010 0.3201 29.647 183,312 2 8/25/2010 0.3027 29.621 194,079 2 8/26/2010 0.2993 13.546 93,683 2 8/28/2010 0.0992 1.178 9,671 2 8/29/2010 0.2742 25.988 187,043 2 8/30/2010 0.3024 31.544 208,567 2 8/31/2010 0.2914 29.6 202,961 2 9/1/2010 0.3032 31.274 206,243 2 9/2/2010 0.2655 26.697 200,547 2 9/3/2010 0.2697 25.059 186,800 2 9/4/2010 0.2585 22.862 176,069 2 9/5/2010 0.331 26.176 157,180 2 9/6/2010 0.312 28.411 175,000 2 9/7/2010 0.3131 31.378 200,025 2 9/8/2010 0.3125 30.693 195,640 2 9/9/2010 0.3145 30.443 192,209 2 9/10/2010 0.3163 31.898 201,819 2 9/11/2010 0.2995 31.21 208,424 2 9/12/2010 0.2738 24.756 180,088 2 9/13/2010 0.2593 23.663 180,788 2 9/14/2010 0.2643 24.632 183,553 2 9/15/2010 0.2785 26.015 184,117 2 9/16/2010 0.2548 24.886 194,499 2 9/17/2010 0.2407 23.854 197,457 2 9/18/2010 0.2501 24.501 195,124 2 9/19/2010 0.2547 20.716 165,500 2 9/20/2010 0.28 26.703 189,739
2 9/21/2010 0.3073 30.549 197,237 2 9/22/2010 0.3044 31.192 204,795 2 9/23/2010 0.2878 29.327 203,673 2 9/24/2010 0.2917 29.842 204,519 2 9/25/2010 0.3368 34.531 205,023 2 9/26/2010 0.3225 25.374 157,556 2 9/27/2010 0.343 30.288 174,395 2 9/28/2010 0.3529 33.819 189,660 2 9/29/2010 0.337 31.985 188,700 2 9/30/2010 0.3067 29.497 190,706 2 10/1/2010 0.3061 26.78 173,646 2 12/1/2010 0.045 0.104 4,636 2 12/2/2010 0.0236 0.135 9,467 2 12/3/2010 0.0877 1.465 18,170 2 12/4/2010 0.104 2.504 23,515 2 12/5/2010 0.2113 6.47 69,803 2 12/6/2010 0.0967 2.243 20,772 2 12/7/2010 0.2328 19.758 169,934 2 12/8/2010 0.2653 22.339 170,105 2 12/9/2010 0.2912 26.479 182,383 2 12/10/2010 0.3654 33.078 180,526 2 12/11/2010 0.3696 32.651 175,081 2 12/12/2010 0.3963 34.441 175,418 2 12/13/2010 0.399 37.477 187,689 2 12/14/2010 0.3696 35.364 191,113 2 12/15/2010 0.336 30.552 177,027 2 12/16/2010 0.3313 29.197 173,761 2 12/17/2010 0.2907 26.929 186,977 2 12/18/2010 0.2787 24.665 179,379 2 12/19/2010 0.3178 26.705 168,255 2 12/20/2010 0.349 33.694 192,951 2 12/21/2010 0.3601 32.432 178,474 2 12/22/2010 0.3515 30.947 175,259 2 12/23/2010 0.351 32.509 184,333 2 12/24/2010 0.2968 22.214 134,210 2 12/25/2010 0.3695 28.806 155,197 2 12/26/2010 0.3838 31.738 167,463 2 12/27/2010 0.3962 33.913 172,104 2 12/28/2010 0.3877 32.717 169,848 2 12/29/2010 0.374 32.493 175,121 2 12/30/2010 0.3763 17.001 92,260 2 1/1/2011 0.1571 10.258 72,888 2 1/2/2011 0.3065 24.754 159,372 2 1/3/2011 0.3377 31.976 188,868 2 1/4/2011 0.3243 29 178,447 2 1/5/2011 0.3359 31.322 186,552 2 1/6/2011 0.3528 32.887 186,140
2 1/7/2011 0.3586 33.09 184,333 2 1/8/2011 0.3365 31.695 188,497 2 1/9/2011 0.3695 32.573 178,845 2 1/10/2011 0.3815 37.065 194,270 2 1/11/2011 0.322 27.342 169,244 2 1/12/2011 0.2904 26.611 182,779 2 1/13/2011 0.329 28.225 171,284 2 1/14/2011 0.3639 29.033 157,835 2 1/15/2011 0.3727 34.019 182,470 2 1/16/2011 0.3495 29.224 167,817 2 1/17/2011 0.3616 35.227 194,763 2 1/18/2011 0.3418 31.47 183,364 2 1/19/2011 0.3505 34.12 194,647 2 1/20/2011 0.362 35.962 198,712 2 1/21/2011 0.409 38.632 188,608 2 1/22/2011 0.3447 29.003 166,832 2 1/23/2011 0.2647 20.198 156,556 2 1/24/2011 0.3425 31.143 178,516 2 1/25/2011 0.3683 35.628 193,152 2 1/26/2011 0.3587 34.163 189,917 2 1/27/2011 0.327 28.503 172,541 2 1/28/2011 0.3474 33.637 193,289 2 1/29/2011 0.2487 21.766 175,190 2 1/30/2011 0.2694 21.502 162,375 2 1/31/2011 0.2805 26.358 187,686 2 2/1/2011 0.2641 25.027 189,268 2 2/2/2011 0.2776 24.727 179,526 2 2/3/2011 0.2923 28.113 191,589 2 2/4/2011 0.3581 36.424 203,281 2 2/5/2011 0.3545 32.365 181,344 2 2/6/2011 0.3216 26.366 162,975 2 2/7/2011 0.3342 32.138 191,591 2 2/8/2011 0.3262 29.09 176,917 2 2/9/2011 0.329 27.564 167,571 2 2/10/2011 0.3225 25.494 157,562 2 2/11/2011 0.3317 29.545 176,463 2 2/12/2011 0.3191 27.466 169,020 2 2/13/2011 0.2287 16.557 134,415 2 2/14/2011 0.2986 22.494 148,370 2 2/15/2011 0.2849 19.686 139,767 2 2/16/2011 0.2948 15.505 106,012 2 2/17/2011 0.2732 14.729 111,337 2 2/18/2011 0.2881 19.392 135,793 2 2/19/2011 0.331 26.26 162,383 2 2/20/2011 0.3196 28.728 179,729 2 2/21/2011 0.3105 29.272 185,021 2 2/22/2011 0.3304 29.663 177,386
2 2/23/2011 0.3506 35.712 203,253 2 2/24/2011 0.3146 31.055 194,571 2 2/25/2011 0.2811 28.443 202,408 2 2/26/2011 0.2765 28.378 205,295 2 2/27/2011 0.2891 27.658 189,608 2 2/28/2011 0.3297 34.86 211,352 2 3/1/2011 0.3283 33.836 206,093 2 3/2/2011 0.331 34.265 206,423 2 3/3/2011 0.3394 35.523 209,307 2 3/4/2011 0.3215 30.34 188,099 2 3/5/2011 0.3319 29.637 178,607 2 3/6/2011 0.3313 27.632 169,866 2 3/7/2011 0.3144 32.563 206,953 2 3/8/2011 0.3067 32.381 211,010 2 3/9/2011 0.3152 31.182 197,610 2 3/10/2011 0.3255 30.724 188,717 2 3/11/2011 0.3295 34.078 206,650 2 3/12/2011 0.3235 34.456 213,036 2 3/13/2011 0.3058 24.608 162,616 2 3/14/2011 0.3025 30.474 199,841 2 3/15/2011 0.2844 26.545 185,436 2 3/16/2011 0.2795 25.471 181,160 2 3/17/2011 0.2815 22.485 158,614 2 3/18/2011 0.292 28.045 192,123 2 3/19/2011 0.3094 32.343 208,308 2 3/20/2011 0.3246 30.831 189,882 2 3/21/2011 0.3083 30.126 194,306 2 3/22/2011 0.3078 28.047 181,559 2 3/23/2011 0.3182 31.24 196,293 2 3/24/2011 0.3351 32.411 192,495 2 3/25/2011 0.3134 25.287 161,512 2 4/22/2011 0.0154 0.032 3,347 2 4/23/2011 0.0797 0.905 10,938 2 4/24/2011 0.2057 6.768 47,080 2 4/25/2011 0.4353 14.765 67,630 2 4/26/2011 0.4074 17.319 90,046 2 4/27/2011 0.3159 26.349 167,264 2 4/28/2011 0.3023 29.551 195,195 2 4/29/2011 0.2912 27.205 187,004 2 4/30/2011 0.2893 27.584 190,167 2 5/1/2011 0.2915 27.14 191,320 2 5/2/2011 0.3033 26.229 174,501 2 5/3/2011 0.2965 28.338 190,403 2 5/4/2011 0.2855 27.677 193,587 2 5/5/2011 0.3054 25.994 175,667 2 5/6/2011 0.3395 20.327 131,417 2 5/7/2011 0.2989 26.32 176,429
2 5/8/2011 0.2846 26.157 181,568 2 5/9/2011 0.2891 24.19 166,892 2 5/10/2011 0.297 27.609 184,996 2 5/11/2011 0.2976 24.67 165,855 2 5/12/2011 0.3067 30.139 195,742 2 5/13/2011 0.2613 18.901 143,927 2 5/14/2011 0.276 21.857 158,210 2 5/15/2011 0.2631 18.014 139,159 2 5/16/2011 0.2928 27.122 183,308 2 5/17/2011 0.2739 22.106 158,795 2 5/18/2011 0.2705 23.72 174,718 2 5/19/2011 0.2911 26.385 179,383 2 5/20/2011 0.2539 20.339 159,868 2 5/21/2011 0.2578 12.945 101,852 2 5/22/2011 0.2976 21.231 144,917 2 5/23/2011 0.2485 14.69 118,399 2 5/24/2011 0.3088 12.364 80,878 2 5/25/2011 0.2932 11.129 76,148 2 5/26/2011 0.3034 10.596 69,987 2 5/27/2011 0.2583 14.89 120,281 2 5/28/2011 0.32 16.437 111,238 2 5/29/2011 0.2447 15.595 130,302 2 5/30/2011 0.2413 20.953 170,818 2 5/31/2011 0.2467 24.483 196,530 2 6/1/2011 0.2744 27.395 196,527 2 6/2/2011 0.2744 26.665 192,143 2 6/3/2011 0.2734 28.35 206,952 2 6/4/2011 0.2702 27.107 199,470 2 6/5/2011 0.2429 14.817 122,241 2 6/6/2011 0.2496 13.002 107,680 2 6/7/2011 0.2536 21.797 167,955 2 6/8/2011 0.268 25.231 184,359 2 6/9/2011 0.2729 26.915 194,932 2 6/10/2011 0.3011 29.11 190,674 2 6/11/2011 0.2943 27.653 184,465 2 6/12/2011 0.2657 19.515 156,987 2 6/13/2011 0.2168 19.877 183,027 2 6/14/2011 0.2618 24.78 185,435 2 6/15/2011 0.2891 29.903 206,659 2 6/16/2011 0.2811 27.153 191,163 2 6/17/2011 0.2731 25.534 185,428 2 6/18/2011 0.2508 22.435 175,735 2 6/19/2011 0.2364 15.654 134,013 2 6/20/2011 0.2294 14.844 130,187 2 6/21/2011 0.2589 25.915 199,965 2 6/22/2011 0.2662 24.749 183,686 2 6/23/2011 0.261 22.766 173,460
2 6/24/2011 0.2989 27.056 177,380 2 6/25/2011 0.3237 30.516 185,524 2 6/26/2011 0.3334 30.913 182,575 2 6/27/2011 0.3429 35.861 208,930 2 6/28/2011 0.294 25.958 174,332 2 6/29/2011 0.2607 22.085 171,964 2 6/30/2011 0.2809 27.622 195,290 2 7/1/2011 0.288 28.731 198,248 2 7/2/2011 0.1999 9.025 61,606 2 7/3/2011 0.2851 28.029 195,550 2 7/4/2011 0.268 21.373 157,070 2 7/5/2011 0.288 25.499 176,014 2 7/6/2011 0.235 23.654 200,501 2 7/7/2011 0.3074 31.39 203,619 2 7/8/2011 0.3149 31.906 200,271 2 7/9/2011 0.3007 27.847 178,256 2 7/10/2011 0.3209 27.654 169,295 2 7/11/2011 0.3645 31.83 178,807 2 7/12/2011 0.2723 24.976 181,806 2 7/13/2011 0.3083 31.829 205,909 2 7/14/2011 0.2963 30.862 208,357 2 7/15/2011 0.3132 32.633 207,754 2 7/16/2011 0.3098 32.203 207,288 2 7/17/2011 0.301 28.777 190,890 2 7/18/2011 0.3318 34.52 207,540 2 7/19/2011 0.3313 33.476 198,487 2 7/20/2011 0.3009 30.804 204,046 2 7/21/2011 0.3122 31.825 202,267 2 7/22/2011 0.3216 33.074 205,062 2 7/23/2011 0.2972 30.875 207,394 2 7/24/2011 0.3365 31.384 186,061 2 7/25/2011 0.3251 31.846 193,676 2 7/26/2011 0.3286 32.634 196,129 2 7/27/2011 0.3365 34.355 201,593 2 7/28/2011 0.3529 37.867 214,033 2 7/29/2011 0.2943 26.439 174,026 2 7/30/2011 0.3167 29.456 178,259 2 7/31/2011 0.3233 30.134 183,246 2 8/1/2011 0.3192 32.162 199,254 2 8/2/2011 0.2609 25.231 192,635 2 8/3/2011 0.2618 25.831 194,914 2 8/4/2011 0.2329 24.194 207,737 2 8/5/2011 0.2261 23.17 204,342 2 8/6/2011 0.2253 23.26 206,213 2 8/7/2011 0.2264 21.331 188,936 2 8/8/2011 0.2853 29.578 206,554 2 8/9/2011 0.2811 28.673 202,776
2 8/10/2011 0.2896 29.131 199,345 2 8/11/2011 0.252 22.855 179,447 2 8/12/2011 0.2611 26.332 200,232 2 8/13/2011 0.2598 25.658 197,416 2 8/14/2011 0.2565 22.782 178,243 2 8/15/2011 0.2477 22.743 183,781 2 8/16/2011 0.2086 19.929 190,837 2 8/17/2011 0.2208 23.255 210,147 2 8/18/2011 0.2521 25.62 202,877 2 8/19/2011 0.2647 27.012 204,403 2 8/20/2011 0.2563 26.25 204,545 2 8/21/2011 0.2664 24.956 186,682 2 8/22/2011 0.2675 27.336 203,535 2 8/23/2011 0.2676 27.43 203,865 2 8/24/2011 0.2668 23.601 178,100 2 8/25/2011 0.2871 28.338 196,837 2 8/26/2011 0.2703 24.915 185,898 2 8/27/2011 0.2457 23.195 189,383 2 8/28/2011 0.2696 22.77 176,413 2 8/29/2011 0.2583 25.34 196,451 2 8/30/2011 0.2771 27.346 197,920 2 8/31/2011 0.2656 28.467 214,333 2 9/1/2011 0.2654 23.516 175,562 2 9/2/2011 0.2482 23.565 187,428 2 9/3/2011 0.2916 30.884 211,687 2 9/4/2011 0.2594 24.55 189,483 2 9/5/2011 0.2502 20.05 161,186 2 9/6/2011 0.2585 20.204 155,925 2 9/7/2011 0.2793 23.578 172,454 2 9/8/2011 0.2599 23.223 178,486 2 9/9/2011 0.2633 22.618 175,494 2 9/10/2011 0.2599 24.196 186,193 2 9/11/2011 0.2642 24.619 187,124 2 9/12/2011 0.247 22.818 184,261 2 9/13/2011 0.246 21.46 174,038 2 9/14/2011 0.2328 19.757 169,212 2 9/15/2011 0.2435 23.005 188,691 2 9/16/2011 0.2602 24.435 186,465 2 9/17/2011 0.2682 26.451 196,960 2 9/18/2011 0.3064 28.174 184,043 2 9/19/2011 0.2624 7.302 55,153 2 9/22/2011 0.134 5.352 44,509 2 9/23/2011 0.3209 31.305 192,018 2 9/24/2011 0.304 28.682 184,634 2 9/25/2011 0.3203 28.745 174,812 2 9/26/2011 0.3344 32.405 192,834 2 9/27/2011 0.3165 31.052 194,835
2 9/28/2011 0.3546 35.064 196,437 2 9/29/2011 0.3133 26.285 165,518 2 9/30/2011 0.3222 25.44 156,812 2 10/1/2011 0.318 26.529 163,164 2 10/2/2011 0.3493 26.624 153,355 2 10/3/2011 0.3246 28.623 174,058 2 10/4/2011 0.3429 29.855 177,266 2 10/5/2011 0.3263 31.736 193,368 2 10/6/2011 0.3228 31.616 194,987 2 10/7/2011 0.295 28.243 190,849 2 10/8/2011 0.3057 31.318 204,446 2 10/9/2011 0.3088 27.552 176,986 2 10/10/2011 0.329 32.957 199,629 2 10/11/2011 0.273 27.712 203,250 2 10/12/2011 0.2425 23.365 191,902 2 10/13/2011 0.2402 23.74 197,459 2 10/14/2011 0.2455 23.187 189,663 2 10/15/2011 0.3059 24.14 155,345 2 10/16/2011 0.2848 25.31 173,345 2 10/17/2011 0.2955 28.576 189,933 2 10/18/2011 0.2881 27.075 186,994 2 10/19/2011 0.2738 24.63 181,250 2 10/20/2011 0.2779 24.269 173,114 2 10/21/2011 0.2913 26.878 182,907 2 10/22/2011 0.3466 36.089 208,037 2 10/23/2011 0.2785 26.041 184,885 2 10/24/2011 0.2721 27.894 204,883 2 10/25/2011 0.2856 28.708 199,779 2 10/26/2011 0.2744 26.353 188,847 2 10/27/2011 0.2793 27.005 191,413 2 10/28/2011 0.2963 30.04 202,311 2 10/29/2011 0.2928 28.162 191,651 2 10/30/2011 0.2954 25.071 167,684 2 10/31/2011 0.3375 31.984 188,030 2 11/1/2011 0.3317 32.563 193,330 2 11/2/2011 0.3139 32.454 206,908 2 11/3/2011 0.2676 23.265 172,204 2 11/4/2011 0.2889 25.527 176,428 2 11/5/2011 0.289 24.936 172,793 2 11/6/2011 0.2969 25.477 171,359 2 11/7/2011 0.262 19.485 129,072 2 11/9/2011 0.1507 6.801 50,118 2 11/10/2011 0.2725 21.016 153,874 2 11/11/2011 0.2444 20.408 165,110 2 11/12/2011 0.3042 26.637 175,346 2 11/13/2011 0.3302 30.458 185,707 2 11/14/2011 0.2984 25.694 170,338
2 11/15/2011 0.2926 20.775 141,914 2 11/16/2011 0.3269 21.819 136,238 2 11/17/2011 0.3152 28.964 184,844 2 11/18/2011 0.3428 33.473 195,154 2 11/19/2011 0.3236 32.434 200,738 2 11/20/2011 0.3436 33.209 192,162 2 11/21/2011 0.3228 32.172 196,138 2 11/22/2011 0.3177 28.567 178,506 2 11/23/2011 0.3145 28.129 176,366 2 11/24/2011 0.3302 21.202 130,692 2 11/25/2011 0.2779 21.25 151,984 2 11/26/2011 0.2963 26.207 173,827 2 11/27/2011 0.3308 27.062 162,932 2 11/28/2011 0.3039 27.534 178,807 2 11/29/2011 0.2962 25.953 175,906 2 11/30/2011 0.3092 24.526 159,232 2 12/1/2011 0.3134 26.167 168,733 2 12/2/2011 0.2819 25.736 181,519 2 12/3/2011 0.3392 24.974 149,365 2 12/4/2011 0.2985 26.271 178,248 2 12/5/2011 0.2946 28.484 193,406 2 12/6/2011 0.289 25.317 179,603 2 12/7/2011 0.2953 21.698 149,209 2 12/8/2011 0.3079 19.546 132,742 2 12/9/2011 0.3015 21.19 147,856 2 12/10/2011 0.2896 26.812 186,436 2 12/11/2011 0.302 27.771 185,936 2 12/12/2011 0.285 23.779 166,663 2 12/13/2011 0.2806 18.117 129,960 2 12/14/2011 0.2838 19.14 134,316 2 12/15/2011 0.2949 23.489 157,149 2 12/16/2011 0.3114 29.531 190,167 2 12/17/2011 0.3121 25.9 165,930 2 12/18/2011 0.327 27.776 168,922 2 12/19/2011 0.3095 25.127 161,665 2 12/20/2011 0.2754 22.849 163,201 2 12/21/2011 0.3067 25.873 164,714 2 12/22/2011 0.3334 27.904 166,210 2 12/23/2011 0.3517 30.803 174,912 2 12/24/2011 0.3165 24.891 158,405 2 12/25/2011 0.3011 17.471 117,238 2 12/26/2011 0.305 25.869 168,332 2 12/27/2011 0.306 25.925 167,343 2 12/28/2011 0.3137 27.543 172,303 2 12/29/2011 0.2716 21.473 158,248 2 12/30/2011 0.2563 18.977 147,671 2 12/31/2011 0.2609 19.478 148,056
Max (tpd) --> 42.329

Max (lb/hr) --> 3527.416667

Note: Dates with no operation/emissions not shown
Entergy Trinity Consultants

BART Analysis – White Bluff

APPENDIX E

S&L NOX CONTROL TECHNOLOGY STUDY
Prepared for 

Gill Elrod Ragon Owen & Sherman, P.A. 

NOx Control Technology Cost 

 and Performance Study 

Entergy Services, Inc. 

White Bluff & Lake Catherine

SL-011439 

Final Report 

Rev. 4 

May 16, 2013 

Project No.: 13027-001

Prepared by 

55 East Monroe Street 

Chicago, IL 60603-5780 USA 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. ii 

LEGAL NOTICE 

This report (“Deliverable”) was prepared by Sargent & Lundy, L.L.C. ("S&L"), expressly for the sole use 

of Gill Elrod Ragon Owen & Sherman, P.A. ("Client") in accordance with the agreement between S&L 

and Client. This Deliverable was prepared using the degree of skill and care ordinarily exercised by 

engineers practicing under similar circumstances. Client acknowledges: (1) S&L prepared this 

Deliverable subject to the particular scope limitations, budgetary and time constraints, and business 

objectives of the Client; (2) information and data provided by others may not have been independently 

verified by S&L; and (3) the information and data contained in this Deliverable are time sensitive and 

changes in the data, applicable codes, standards, and acceptable engineering practices may invalidate the 

findings of this Deliverable. Any use or reliance upon this Deliverable by third parties shall be at their 

sole risk. 


Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. v 

1. INTRODUCTION..........................................................................................................................1

1.1. OBJECTIVE...................................................................................................................................1

1.2. UNIT DESCRIPTIONS .................................................................................................................1

1.2.1. White Bluff - Units 1 & 2...............................................................................................................1

1.2.2. White Bluff Auxiliary Boiler..........................................................................................................1

1.2.3. Lake Catherine - Unit 4 ..................................................................................................................1

1.3. ESTIMATE METHODOLOGY ....................................................................................................2

1.3.1. Capital Cost Estimates....................................................................................................................2

1.3.2. Operating and Maintenance Cost Estimates...................................................................................3

1.4. DESIGN TARGET vs. COMPLIANCE NOX EMISSION RATES ..............................................3

2. WHITE BLUFF - UNITS 1 & 2.....................................................................................................4

2.1. FUEL SWITCHING OPTIONS.....................................................................................................4

2.1.1. Natural Gas.....................................................................................................................................4

2.1.2. Propane...........................................................................................................................................4

2.2. COMBUSTION CONTROLS........................................................................................................4

2.2.1. Low NOx Burners and Over-Fire Air ............................................................................................4

2.2.2. Flue Gas Recirculation (FGR)........................................................................................................5

2.2.3. Neural Network ..............................................................................................................................5

2.3. POST COMBUSTION CONTROLS.............................................................................................6

2.3.1. Selective Non-Catalytic Reduction ................................................................................................6

2.3.2. Selective Catalytic Reduction.........................................................................................................7

2.4. CAPITAL COSTS..........................................................................................................................8

2.5. OPERATING AND MAINTENANCE COSTS ............................................................................9

3. WHITE BLUFF AUXILIARY BOILER .....................................................................................11

3.1. FUEL SWITCHING.....................................................................................................................11

3.2. COMBUSTION CONTROLS......................................................................................................11

3.2.1. Low NOx Burners + Over-Fire Air..............................................................................................11

3.2.2. Flue Gas Recirculation .................................................................................................................11

3.2.3. Low NOx Burners + Over-fire Air + Flue Gas Recirculation......................................................11

3.2.4. Neural Network ............................................................................................................................12

3.3. POST COMBUSTION CONTROLS...........................................................................................12

3.3.1. Selective Non-Catalytic Reduction ..............................................................................................12

3.3.2. Selective Catalytic Reduction.......................................................................................................12
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. vi 

3.4. CAPITAL COST ESTIMATES ...................................................................................................13

3.5. OPERATING AND MAINTENANCE COST ESTIMATES .....................................................13

4. LAKE CATHERINE - UNIT 4....................................................................................................15

4.1. FUEL SWITCHING.....................................................................................................................15

4.2. COMBUSTION CONTROLS......................................................................................................15

4.2.1. Burners-Out-Of-Service ...............................................................................................................15

4.2.2. Low NOx Burners + Over-Fire Air..............................................................................................16

4.2.3. Flue Gas Recirculation .................................................................................................................16

4.2.4. Water Injection .............................................................................................................................16

4.2.5. Neural Network ............................................................................................................................17

4.3. POST COMBUSTION CONTROLS...........................................................................................17

4.3.1. Selective Non-Catalytic Reduction ..............................................................................................17

4.3.2. Selective Catalytic Reduction.......................................................................................................17

4.4. CAPITAL COST ESTIMATES ...................................................................................................18

4.5. OPERATING AND MAINTENANCE COST ESTIMATES .....................................................19

APPENDIX A: CAPITAL COST ESTIMATE........................................................................................2

1. BASIS OF ESTIMATES................................................................................................................2

2. CONCEPTUAL COST ESTIMATE SUMMARY SHEETS ........................................................2

APPENDIX B ..............................................................................................................................................3

1. ESTIMATED PROJECT SCHEDULES........................................................................................3

APPENDIX C..............................................................................................................................................4

1. OPERATING AND MAINTENANCE COST ESTIMATES .......................................................4

APPENDIX D..............................................................................................................................................5

1. BOOS AT FULL UNIT LOAD .....................................................................................................5
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 1 

1. INTRODUCTION 

1.1. OBJECTIVE 

The intent of this study is to provide Gill Elrod Ragon Owen & Sherman, P.A. with a technology 

evaluation and cost estimates for available methods of NOx control at two Entergy stations including: 

White Bluff – Units 1 & 2, the White Bluff Auxiliary Boiler, and Lake Catherine – Unit 4. The 

information developed in this study will be used to create a BART analysis, for compliance with 

Arkansas DEQ regulations. 

1.2. UNIT DESCRIPTIONS 

1.2.1. White Bluff - Units 1 & 2 

White Bluff - Units 1 & 2 are Alstom-designed, tangentially-fired, pulverized-coal fueled units, rated at 

815 MWnet and 844 MWnet respectively. Powder River Basin coal is the primary fuel source for Units 1 

& 2. Currently, the units have no NOx controls installed. 

1.2.2. White Bluff Auxiliary Boiler 

The White Bluff Auxiliary boiler is a small industrial boiler capable of producing 140,000 lb/hr of steam, 

used for startup of the White Bluff coal units. The auxiliary boiler combusts No. 2 Diesel Oil, and does 

not have any existing NOx controls. 

1.2.3. Lake Catherine - Unit 4 

Lake Catherine - Unit 4 is an Alstom-designed, tangentially-fired, natural gas fueled unit, capable of 

generating 558 MWnet. The unit was originally designed as a dual-fuel unit, able to use natural gas or 

No. 2 Fuel Oil as fuel. This evaluation will be for natural gas firing only. If No. 2 Fuel Oil is to be 

combusted in the future, a separate BART analysis will be submitted. The unit currently has no NOx 

controls. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 2 

1.3. ESTIMATE METHODOLOGY 

1.3.1. Capital Cost Estimates 

S&L’s capital cost estimates for retrofit NOx control technologies for White Bluff Units 1&2, White 

Bluff Auxiliary Boiler and Lake Catherine – Unit 4 encompass the equipment, material, labor, and all 

other required direct costs. The underlying assumption is that the project will be implemented on a 

multiple-contracting basis. The capital cost estimates provided herein are “total plant cost,” and include 

the following: 

 Equipment and material 

 Installation labor 

 Indirect field costs and BOP engineering 

 Contingency (percentage varies with project size) 

 Erection contractor profit (at 10% of material and labor) 

 General and administration (at 5% of material and labor) 

 Freight on material (at 5% of material) 

 Freight on equipment (included with equipment costs) 

 Sales/use tax (not included) 

 Startup and commissioning (at 1% of construction cost) 

 Spare parts (included with equipment costs) 

 Consumables (0.5% of material and labor) 

Owner’s engineering and other Owner’s costs were not included. Engineering, Procurement & Project 

Services and Contingency varied depending on the size of the project. License fees and royalties are not 

expected for the proposed control strategies. The Basis of Estimate and capital costs are summarized in 

Appendix A. 

Capital cost estimates were calculated in one of three ways. In some cases, vendors were contacted to 

provide budgetary estimates for equipment and labor. These vendor’s costs were used to create Total 

Installed Cost Estimates. In situations where Sargent & Lundy had performed cost estimates for these 

units previously, the existing cost estimates were updated to reflect current equipment, labor, and 

currency values. Remaining cost estimates were developed from similar projects that Sargent & Lundy 

has completed and adjusted for unit size. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 3 

1.3.2. Operating and Maintenance Cost Estimates 

Operating and Maintenance Costs for White Bluff - Units 1 & 2 and Lake Catherine – Unit 4 were 

developed from similar projects Sargent & Lundy has completed. Costs were applied to the units on a 

$/kW basis, and assuming a 10% capacity factor for Lake Catherine – Unit 4, and 76% for White Bluff—

Units 1 & 2. Operating and Maintenance Costs include the following costs: 

 Fixed Operating and Maintenance 

 Variable Operating and Maintenance 

 Fuel Impact Costs 

For the White Bluff Auxiliary boiler, costs were developed using Office of Air Quality Planning and 

Standards (OAQPS) calculations, assuming a 10% capacity factor. 

1.4. DESIGN TARGET vs. COMPLIANCE NOX EMISSION RATES 

NOx control systems retrofit onto existing coal or gas-fired boilers are typically designed to achieve 

varying levels of NOx removal efficiencies from 10%-94%, depending on the control technologies 

selected. Controlled NOx emissions fluctuate during normal boiler operation in response to a number of 

design/operating parameters including, but not necessarily limited to: inlet NOx concentrations, boiler 

load, load changes, particulate matter loading, flue gas temperatures, flue gas velocities and mixing, 

catalyst volume and surface area, NH3:NOx stoichiometric ratio, catalyst age and activity, and the 

quantity of ammonia slip deemed to be acceptable. 

The “design target” NOx emission rate is the rate that a NOx control technology vendor would be willing 

to guarantee. Based on engineering judgment, and taking into consideration emissions data from existing 

coal- and gas-fired sources, a compliance margin above the design target is recommended for high 

removal efficiency/low emission rate technologies (such as SCR) to establish an enforceable permit limit 

based on long-term (e.g., annual average) emissions. Additional compliance margin would be required to 

establish enforceable permit limits based on shorter-term averaging times. For example, S&L 

recommends a compliance margin of 0.02 to 0.03 lb/MMBtu for coal units and 0.01 to 0.02 lb/MMBtu 

for gas units above the design target emission rate for permit limits based on a 30-day rolling average for 

control strategies including SCR. The NOx control technology emission rates for strategies including 

SCR in this report have been adjusted to include margin for compliance. The permit level NOx emission 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 4 

rates for SCR are higher by 0.02 to 0.03 lb/MMBtu for coal units and 0.01 to 0.02 lb/MMBtu for gas 

units. 

2. WHITE BLUFF - UNITS 1 & 2 

2.1. FUEL SWITCHING OPTIONS 

2.1.1. Natural Gas 

For White Bluff Units 1 & 2, fuel switching is not a feasible option. Typically, units could be switched 

from coal to natural gas or propane for NOx reductions. The nearest natural gas pipeline to the White 

Bluff facility is approximately 20 miles away. Construction of a pipeline is currently estimated at $2M 

per mile resulting in a cost of $40M to bring natural gas to the site, not including the additional upgrades 

the boiler would require to burn natural gas instead of coal. 

2.1.2. Propane 

White Bluff – Units 1 & 2 are each over 800 MWnet. Units of this size require more heat input than can 

practically be achieved with a propane delivery and storage system. Since a propane pipeline is not 

available, fuel switching to propane is not a feasible option. 

2.2. COMBUSTION CONTROLS 

2.2.1. Low NOx Burners and Over-Fire Air 

Low NOx burners (LNB) limit NOx formation by controlling both the stoichiometric and temperature 

profiles of the combustion flame in each burner flame envelope. Control is achieved with design features 

that regulate the aerodynamic distribution and mixing of the fuel and air, yielding reduced oxygen (O2) in 

the primary combustion zone, reduced flame temperature, and reduced residence time at peak combustion 

temperatures. The combination of these techniques produces lower NOx emissions during the combustion 

process. 

OFA involves injecting combustion air downstream of the fuel-rich primary combustion zone by using 

over-fire air or side-fired air ports. The fuel-rich mixture that is fed to the burners reduces the flame 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 5 

temperature and oxygen concentration thus reducing the formation of thermal NOx. Generally, OFA is 

more effective when used with low nitrogen content fuels such as natural gas and propane, since OFA is 

more effective in controlling thermal NOx rather than fuel NOx. 

LNB + OFA is a technically feasible retrofit solution for White Bluff - Units 1 & 2. The combination of 

LNB + OFA is capable of achieving a NOx emission rate of 0.15 lb/MMBtu. From Unit 1’s baseline 

emissions of 0.33 lb/MMBtu, this is approximately 54.5% NOx removal efficiency. A removal efficiency 

of 61.5% can be expected for Unit 2, with a baseline NOx of 0.39 lb/MMBtu. 

2.2.2. Flue Gas Recirculation (FGR) 

NOx reduction efficiency data for coal-fired units with FGR are limited. The amount of NOx reduction 

achievable with FGR depends primarily on the fuel nitrogen content and amount of FGR used. Generally, 

FGR is more effective when used with low nitrogen content fuels such as natural gas and propane, since 

FGR is more effective in controlling thermal NOx rather than fuel NOx. Industry experience with FGR on 

coal-fired units for steam temperature control has shown very high maintenance on the gas recirculation 

fans due to erosion and corrosion. Many of the units with FGR for steam temperature control have 

removed the recirculation fans from service. The NOx control achievable on tangentially fired units like 

White Bluff – Units 1&2 with LNB+OFA has been comparable to that of FGR at lower capital and O&M 

cost. Currently, FGR technology is not offered by OEMs for coal-fired units. For these reasons, FGR is 

not a feasible technology for the White Bluff coal-fired units. 

2.2.3. Neural Network 

Neural Network (NN) systems are on-line enhancements to digital control systems (DCS) and plant 

information systems that improve boiler performance parameters such as heat rate, NOx emissions, and 

CO levels. The Neural Network model is based on historical data and parametric test data. The software 

applies an optimizing procedure to identify the best set points for the boiler, which are implemented 

without operator intervention (closed loop), or, at the plant’s discretion, conveyed to the plant operators 

for implementation (open loop). 

A Neural Network system is a technically feasible retrofit option for the White Bluff units. A NN is 

already installed for monitoring and controlling heat rate at White Bluff – Units 1&2. The reprogrammed 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 6 

NN would be optimized first for minimizing NOx emissions and second for heat rate. It is possible that 

heat rate may increase as a result. Based on information available from vendors, it is expected that Neural 

Network technology on a coal-fired boiler can maintain the guaranteed performance of low NOx burners 

and potentially can achieve approximately 10% NOx reduction over a period of years, resulting in NOx 

emission rates of 0.30 lb/MMBtu, at max load for Unit 1, and of 0.35 lb/MMBtu for Unit 2. The cost for 

modifying the existing NNs at White Bluff is estimated to be approximately $250,000 per unit. 

2.3. POST COMBUSTION CONTROLS 

2.3.1. Selective Non-Catalytic Reduction 

Selective non-catalytic reduction (SNCR) involves the direct injection of ammonia (NH3) or urea 

(CO(NH2)2) into the furnace at high flue gas temperatures (approximately 1600 oF – 2000 oF). The 

ammonia or urea reacts with NOx in the flue gas to produce N2 and water as shown in the following 

equations: 

(CO(NH2)2) + 2NO + 1⁄2O2 → 2H2O + CO2 + 2N2

2NH3 + 2NO + 1⁄2O2 → 2N2 + 3H2O 

Flue gas temperature at the point of reactant injection can greatly affect NOx removal efficiencies and the 

quantity of NH3 or urea that will pass through the furnace unreacted (referred to as NH3 slip). In general, 

SNCR reactions are effective at a temperature range of 1600 oF – 2000 oF. At temperatures below the 

desired operating range, the NOx reduction reactions diminish and unreacted NH3 emissions increase. 

Above the desired temperature range, NH3 is oxidized to NOx resulting in low NOx reduction 

efficiencies. 

Mixing of the reactant and flue gas within the reaction zone is also an important factor to SNCR 

performance. In large boilers, the physical distance over which reagent must be dispersed increases, and 

the surface area/volume ratio of the convective pass decreases. Both of these factors make it difficult to 

achieve good mixing of reagent and flue gas, delivery of reagent in the proper temperature window, and 

sufficient residence time of the reactant and flue gas in that temperature window. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 7 

The temperatures and residence times required for an SNCR system make it a feasible option for NOx 

reduction for White Bluff - Units 1 & 2. Based on vendor input, a unit with no additional controls and a 

baseline NOx of 0.33 lb/MMBtu could see a 26.5% NOx reduction, for an outlet rate of 0.24 lb/MMBtu 

on Unit 1. For Unit 2, with a baseline NOx of 0.39 lb/MMBtu could see a 26.5% reduction to an outlet 

rate of 0.29 lb/MMBtu. 

SNCR systems can also be installed in conjunction with LNB + OFA controls. On these coupled systems, 

the starting NOx of approximately 0.15 lb/MMBtu can be reduced to 0.13 lb/MMBtu, for a total reduction 

(LNB + OFA + SNCR) of around 61% for Unit 1 and 67% for Unit 2. In addition to the SNCR 

equipment, the process requires additional demineralized water at a rate of 170 gpm. An additional water 

treatment system capable of providing the required flows is included in the capital cost. The cost of the 

SNCR equipment for the combination technology would be approximately 10% lower based on the lower 

starting NOx rate with LNB/OFA. 

2.3.2. Selective Catalytic Reduction 

Selective Catalytic Reduction (SCR) involves injecting ammonia into boiler flue gas in the presence of a 

catalyst to reduce NOx to N2 and water. The overall SCR reactions are: 

4NH3 + 4NO + O2 → 4N2 + 6H2O 

8NH3 + 4NO2 + 2O2 → 6N2 + 12H2O 

The optimal temperature range depends on the type of catalyst used, but is typically between 560 °F and 

800 °F to maximize NOx reduction efficiency and minimize ammonium sulfate formation. Below this 

range, ammonium sulfate is formed resulting in catalyst deactivation. Above the optimum temperature, 

the catalyst will sinter and thus deactivate rapidly. Another factor affecting SCR performance is the 

condition of the catalyst material. As the catalyst degrades over time or is damaged, NOx removal 

decreases which is typically compensated by increased ammonia slip. 

SCR has been installed on many large coal-fired and some gas-fired boilers and is considered a feasible 

technology. Because of the expense of the reagent, SCR systems are usually installed on units with 

existing LNB + OFA systems, or the upgrades are done simultaneously. At White Bluff, an 

SCR+LNB/OFA system is capable of removing approximately 90% of NOx emissions on a continuous 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

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Final Report Rev. 4 

5/16/2013 

Page No. 8 

long-term basis. With a starting NOx of 0.33 lb/MMBtu (Unit 1) to 0.39 lb/MMBtu (Unit 2), an SCR can 

be expected to achieve permitted emissions compliance at 0.055 lb/MMBtu. 

2.4. CAPITAL COSTS 

Capital costs for the technically feasible control options for the White Bluff coal units are listed in Table 

2.1. The cost of SCR on White Bluff – Unit 1 is higher than for White Bluff – Unit 2 because the 

ductwork arrangement is different and there is more total ductwork, support steel, and foundations for 

Unit 1. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

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Page No. 9 

Table 2.1: Expected NOx Emissions and Capital Costs, White Bluff Units 1 & 2 

Controlled NOx 

(lb/MMBTU) Technology 

Unit 1 Unit 2 

Unit 1 Total 

Installed Capital 

Cost (2012$) 

Unit 2 Total 

Installed Capital 

Cost (2012$) 

Baseline 0.33 0.39 NA NA 

LNB + OFA 0.15 0.15 7,804,0001 11,831,000 

Neural Network 0.30 0.35 250,0002 250,0002

SNCR 0.24 0.29 9,372,000 9,372,000 

SNCR (+ LNB/OFA) 0.13 0.13 16,290,0001 20,317,000 

SCR (+ LNB/OFA) 0.055 0.055 202,601,000 178,240,000 

1. LNB/OFA material already purchased for Unit 1. The total cost to Entergy would be the same for 

Unit 1 as shown for Unit 2. 

2. The cost for modifying the existing neural networks on Units 1 & 2. 

2.5. OPERATING AND MAINTENANCE COSTS 

Annual Operating and Maintenance costs for each of the feasible technologies for White Bluff Units 1 & 

2 are shown in Table 2.2. Costs were calculated assuming full load operation, and a capacity factor (C.F.) 

of 76%. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

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Page No. 10 

Table 2.2: Operating and Maintenance Costs, White Bluff – Units 1 & 2 (Based on a C.F. of 76%) 

 Unit 1 Unit 2 

Technology 

Variable 

O&M1 

Costs 

(2012$)

Fixed 

O&M 

Costs 

(2012$) 

Total 

O&M 

Costs 

(2012$) 

Variable 

O&M1

Costs 

(2012$) 

Fixed 

O&M 

Costs 

(2012$) 

Total 

O&M 

Costs 

(2012$) 

LNB + OFA -- 142,000 142,000 -- 142,000 142,000 

Neural Network -- 50,000 50,000 -- 50,000 50,000 

SNCR 5,658,000 169,000 5,827,000 6,671,000 169,000 6,840,000 

SNCR (+ LNB/OFA) 4,538,000 311,000 4,849,000 4,542,000 311,000 4,853,000 

SCR (+ LNB/OFA) 2,836,000 608,000 3,444,000 2,858,000 608,000 3,466,000 

Note 1: Variable O&M includes fuel cost impacts. 

Note 2: The current costs of ammonia and urea are highly volatile and may exceed the values used in this 

report. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

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Final Report Rev. 4 

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Page No. 11 

3. WHITE BLUFF AUXILIARY BOILER 

3.1. FUEL SWITCHING 

The White Bluff auxiliary boiler is a B&W, single burner boiler, firing No. 2 diesel oil, rated at 140,000 

lb/hr of steam. Fuel switching to natural gas or propane is not practical because the nearest natural gas 

pipeline is 20 miles from the site. The costs to convert the White Bluff aux boiler to either natural gas or 

propane would not be justified based on the low capacity factor. 

3.2. COMBUSTION CONTROLS 

3.2.1. Low NOx Burners + Over-Fire Air 

For an auxiliary boiler such as the one at White Bluff, NOx reduction can be achieved with a combination 

of technologies. LNB + OFA for aux boilers achieve NOx reduction under the same principles as a coal 

boiler. By modifying temperatures and fuel-rich areas, less NOx is generated. LNB + OFA are feasible 

technologies for auxiliary boilers, and vendor data indicates that the White Bluff Aux Boiler could 

achieve 35% reduction with LNB + OFA, for a final emission of 0.11 lb/MMBtu. The baseline NOx 

emissions from the White Bluff aux boiler are calculated using US EPA’s AP-42 emissions factors. 

3.2.2. Flue Gas Recirculation 

NOx reduction efficiency data for oil-fired units with FGR are limited. The amount of NOx reduction 

achievable with FGR depends primarily on the fuel nitrogen content and amount of FGR used. Generally, 

FGR is more effective when used with low nitrogen content fuels such as natural gas and propane, since 

FGR is more effective in controlling thermal NOx rather than fuel NOx. FGR is a feasible technology for 

the White Bluff auxiliary boiler. With a recirculation of 15% of the flue gas, the unit could expect to see 

13% NOx removal, for an outlet of 0.149 lb/MMBtu. 

3.2.3. Low NOx Burners + Over-fire Air + Flue Gas Recirculation 

These three technologies are often installed simultaneously for greater NOx reduction. A vendor has 

proposed that for the White Bluff aux boiler, a combination of LNB + OFA + FGR will reduce the NOx 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

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Final Report Rev. 4 

5/16/2013 

Page No. 12 

from 0.171 lb/MMBtu to 0.100 lb/MMBtu when burning No. 2 Fuel Oil. This reduction of 42% will 

come from a new LNB and OFA system and the recirculation of 15% of the flue gas flow. 

3.2.4. Neural Network 

The White Bluff Auxiliary Boiler is not a candidate for a neural network (NN) because there are few 

controllable variables to be optimized. The aux boiler also uses a relatively new PLC control system. 

3.3. POST COMBUSTION CONTROLS 

3.3.1. Selective Non-Catalytic Reduction 

SNCR control has proven to be difficult to apply to industrial boilers because of the temperature and 

mixing requirements, especially industrial boilers that modulate or cycle frequently. In order to 

effectively reduce NOx emissions, the reactant (ammonia or urea) must be injected into the flue gas 

within a specific flue gas temperature window, and must remain within that temperature window for a 

sufficient residence time. In industrial boilers that cycle frequently, the location of the specific exhaust 

gas temperature window is constantly changing. Thus, SNCR has not been effective on industrial boilers 

that have high turndown capabilities and modulate or cycle frequently. Based on the temperature and 

residence time requirements associated with effective NOx reduction, the planned use of the auxiliary 

boiler, and the limited availability of SNCR control systems for industrial boilers, it has been determined 

that SNCR is not technically feasible for the White Bluff auxiliary boiler. 

3.3.2. Selective Catalytic Reduction 

SCR for NOx control on auxiliary boilers is not common, because of their cycling operation, and the use 

of fuel oil. SCRs have critical operating temperature ranges, which are difficult to achieve and maintain 

in short periods of time. Because of the sulfur content of diesel oil, the SCR catalyst can become 

poisoned, resulting in a lower NOx removal efficiency. With this lower efficiency and high cost, an SCR 

is not considered a feasible technology. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

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Final Report Rev. 4 

5/16/2013 

Page No. 13 

3.4. CAPITAL COST ESTIMATES 

Capital costs for the technically feasible control options for the White Bluff Auxiliary Boiler are listed in 

Table 3.1. 

Table 3.1: Expected NOx Emissions and Capital Costs, White Bluff Units 1 & 2 

Technology Controlled NOx Total Installed Capital 

Cost (2012$) 

Baseline 0.171 -- 

LNB 0.111 255,000 

OFA 0.137 231,000 

FGR 0.149 366,000 

LNB + OFA + FGR 0.100 852,000 

3.5. OPERATING AND MAINTENANCE COST ESTIMATES 

Annual Operating and Maintenance costs for each of the feasible technologies for White Bluff Units 1 & 

2 are shown in Table 3.2. Costs were calculated assuming full load operation and a capacity factor (C.F.) 

of 10%. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

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Final Report Rev. 4 

5/16/2013 

Page No. 14 

Table 3.2: White Bluff Auxiliary Boiler Operating and Maintenance Costs (Based on a C.F. of 10%) 

Technology 

Variable O&M 

Costs (2012$) 

Fixed O&M 

Costs (2012$) 

Total O&M 

Costs (2012$) 

LNB 4,000 4,000 8,000 

OFA 5,000 4,000 9,000 

FGR 0 7,000 7,000 

LNB + OFA + FGR 9,000 15,000 24,000 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 15 

4. LAKE CATHERINE - UNIT 4 

4.1. FUEL SWITCHING 

Lake Catherine - Unit 4 already combusts natural gas, which has the lowest NOx formation of potential 

fuels. Because fuel switching would not result in a lower NOx emission rate, it is not a feasible option for 

NOx control. 

4.2. COMBUSTION CONTROLS 

4.2.1. Burners-Out-Of-Service 

Burners-Out-Of-Service (BOOS) allows operators to stop fuel flow to certain burners in the boiler 

(typically the top level of burners), while air flow is maintained. By removing fuel from the top row of 

burners, the combustion air becomes over-fire air and the production of thermal NOx is reduced. While 

the reduction of NOx can be significant, the tradeoff is a reduced generating capacity, if no further 

modifications to the firing system are made. BOOS is a feasible technology for Lake Catherine - Unit 4. 

Testing of BOOS at Lake Catherine by Entropy Technology & Environmental Consultants, Inc. (ETEC) 

with the top levels of burners out resulted in a maximum load of 405 MW, a 28% reduction in capacity, 

and NOx levels of 0.12 lb/MMBtu, a reduction of 55% from the baseline while using the existing burners. 

Recovery of the lost unit capacity is possible by increasing the fuel fired in the three levels of burners that 

remain in service. The burners remaining in service would have to increase fuel throughput by 25%. The 

natural gas piping to each burner may also have to be increased in size for the higher fuel flow rates. 

ETEC, Inc. has experience with several units similar in design to Lake Catherine – Unit 4 that have been 

able to achieve full capacity by increasing the original “high” burner header pressure (BHP) to increase 

fuel flow to the burners (See Appendix D). The increase in BHP from 42 to 50 psig at Lake Catherine – 

Unit 4 would increase fuel flow by 25% and the burners would be operated “fuel rich”, lowering NOx 

formation. Using this approach would reduce NOx emissions at a small capital cost. The costs for BOOS 

with recovery of full unit capacity were based on vendor cost information for a previous project adjusted 

on a $/kW basis to Lake Catherine – Unit 4 and escalated to 2012. The cost provided does not include 

any modifications to the boiler. A boiler OEM or consultant would need to evaluate the existing fuel 

piping, superheat and reheat attemperation sprays, tube metal temperatures and burner tilt positions for 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

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Page No. 16 

the new operating conditions. The expected NOx reduction would range from 40% at low load to 50% at 

full load and NOx levels of 0.24 lb/MMBtu. 

4.2.2. Low NOx Burners + Over-Fire Air 

Low NOx Burners and Over-Fire Air for a gas-fired unit function similarly to coal-fired boilers, as 

discussed for White Bluff - Units 1 & 2. By controlling the temperature and stoichiometric profiles, the 

NOx produced as a result of thermal processes is reduced. 

LNB + OFA are commonly installed on gas-fired units of this size, and are a feasible retrofit technology 

for Lake Catherine - Unit 4. With the installation of LNB + OFA, Lake Catherine could expect a 60% 

reduction in NOx, from 0.4825 lb/MMBtu to 0.19 lb/MMBtu. 

4.2.3. Flue Gas Recirculation 

Flue Gas Recirculation (FGR) reduces NOx by recirculating flue gas to the furnace. This recirculated gas 

has lower oxygen content than ambient air usually used for combustion. Lower oxygen and lower flame 

temperatures reduces thermal NOx formation. FGR can be installed on a unit in two ways. Traditional 

FGR installations require a new recirculation fan. Induced FGR, or IFGR, installs ductwork from the air 

preheater outlet to the suction of the existing forced draft fan. IFGR does not require a separate fan, but 

due to FD fan capacity restrictions, IFGR is not available at higher loads, because the forced draft fans 

were not designed for the higher air and gas flow rate. 

FGR is technically feasible on Lake Catherine - Unit 4 and can result in reductions of 60%. For Unit 4, 

this would be equivalent to NOx emissions of 0.19 lb/MMBtu. 

4.2.4. Water Injection 

Water injection operates on similar principles to LNB + OFA and FGR. By injecting water into the 

furnace, the temperature of the flue gas is reduced, thereby reducing the amount of thermal NOx formed. 

Water injection is a feasible technology for Lake Catherine - Unit 4, and can reduce NOx emissions by 

9% at full load. Water injection is typically used as a trimming technology at high load. On Unit 4, the 

emissions would be lowered from the baseline of 0.4825 lb/MMBtu to 0.44 lb/MMBtu. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

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Final Report Rev. 4 

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Page No. 17 

4.2.5. Neural Network 

Lake Catherine – Unit 4 could also install a neural network (NN) but for the low capacity factor and 

current lack of NOx CEMS, a NN would not be practical. Several of the other technologies would provide 

greater NOx reductions. 

4.3. POST COMBUSTION CONTROLS 

4.3.1. Selective Non-Catalytic Reduction 

Selective Non-Catalytic Reduction for gas-fired units operates under the same principles as SNCR for 

coal-fired units, with a few design changes. One of the keys of SNCR design is adequate chemical 

distribution at the right temperature for the reaction. Lake Catherine - Unit 4 has horizontal superheat 

platens, which requires multiple-nozzle lances to distribute the urea; the gas pattern does not provide 

adequate distribution. The reaction and temperature requirements are the same for gas-fired boilers as 

they are for coal-fired units. 

SNCR has been installed on boilers such as Lake Catherine 4 and is considered a feasible technology, 

although the residence time in the desired temperature zone is lower for a gas-fired unit and the 

temperature window moves as unit load changes. The unit could expect to see reductions in NOx from 

the baseline of 0.4825 lb/MMBtu to 0.29 lb/MMBtu, or approximately 40% reduction at full load. In 

addition to the SNCR equipment, the process requires additional demineralized water at a rate of 85 gpm. 

An additional water treatment system capable of providing the required flows is included in the capital 

cost. 

SNCR can be combined with LNB/OFA to achieve a combined NOx removal efficiency of 70% for an 

outlet emission of approximately 0.14 lb/MMBtu, 

4.3.2. Selective Catalytic Reduction 

Selective Catalytic Reduction units are similar for gas and coal-fired units. Ammonia or urea reagent 

reacts with NOx to form nitrogen and water, in the presence of a catalyst. Because gas boilers do not 

have particulate control or sulfur dioxide control, they typically have a shorter distance from the 

economizer outlet to the stack, which may result in long ductwork runs to and from the SCR. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

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Final Report Rev. 4 

5/16/2013 

Page No. 18 

SCR is a feasible technology for Lake Catherine - Unit 4. Combined with a LNB + OFA installation, 

which is typical of SCR installations, the unit could achieve a combined NOx removal efficiency of 94%, 

for a permitted outlet NOx of 0.03 lb/MMBtu at full load. This includes a margin for compliance as 

discussed in Section 1.4. Without the LNB + OFA installed, the SCR can also be designed to achieve 

90% removal efficiency for an outlet emission of approximately 0.05 lb/MMBtu. 

4.4. CAPITAL COST ESTIMATES 

Capital costs for the technically feasible control options for Lake Catherine - Unit 4 are listed in Table 

4.1. 

Table 4.1: Expected NOx Emissions and Capital Costs, Lake Catherine Unit 4 

Technology 

Controlled NOx 

(lb/MMBtu) 

Total Installed Capital 

Cost (2012$) 

Baseline 0.4825(1) -- 

BOOS (at full capacity) 0.24 893,000 

LNB / OFA 0.19 8,762,000 

IFGR (below 500 MW) 0.39 2,166,000 

FGR 0.19 11,489,000 

Water Injection 0.44 2,177,000 

SNCR 0.29 15,507,000 

SNCR (+ LNB/OFA) 0.14 24,269,000 

SCR 0.05 59,587,000 

SCR (+ LNB/OFA) 0.03 68,349,000 

Note 1: The baseline NOx rate is the maximum daily emission rate from the 2001-2003 

baseline period. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

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Page No. 19 

4.5. OPERATING AND MAINTENANCE COST ESTIMATES 

Annual Operating and Maintenance costs for each of the feasible technologies for Lake Catherine - Unit 4 

are shown in Table 4.2. Costs were calculated assuming full load operation, and a capacity factor (C.F. of 

10%). 

Table 4.2: Annual Operating and Maintenance Costs, Lake Catherine Unit 4 (Based on C.F. of 10%) 

Technology 

Variable 

O&M1,2 

Costs 

(2012$)

Fixed 

O&M 

Costs 

(2012$) 

Total 

O&M 

Costs 

(2012$) 

BOOS -- 21,000 21,000 

LNB + OFA -- 210,000 210,000 

IFGR -- 52,000 52,000 

FGR 142,000 207,000 349,000 

Water Injection 486,000 52,000 538,000 

SNCR 1,640,000 279,000 1,919,000 

SNCR (+ LNB/OFA) 462,000 489,000 951,000 

SCR 254,000 358,000 612,000 

SCR (+ LNB/OFA) 268,000 568,000 836,000 

Note 1: Variable O&M includes fuel cost impacts. 

Note 2: The current costs of ammonia and urea are highly 

volatile and may exceed the values used in this report. 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 2 

APPENDIX A: CAPITAL COST ESTIMATE 

1. BASIS OF ESTIMATES 

2. CONCEPTUAL COST ESTIMATE SUMMARY SHEETS 
Client:  Entergy  Preparer:  A Hays 

Station:  White Bluff/Lake Catherine  Date:         09/04/2012 (Rev 0) 

Project No.: 13027‐001 

 

Basis of Estimate 

Estimates: 

31813A – Lake Catherine, Unit 4 - Low NOx Burners and Over Fired Air 

31814A – Lake Catherine, Unit 4 - SCR 

31815A – Lake Catherine, Unit 4 - SNCR 

31816A – White Bluff, Unit 1 - Low NOx Burners and Over Fired Air 

31817A – White Bluff, Unit 1 – SCR 

31818A – White Bluff, Unit 2 – SCR 

31819A – White Bluff, Units 1 and 2 – SNCR 

31820A – White Bluff, Auxiliary Boiler – Low NOx Burners, Over Fired Air, and Flue Gas Recirculation 

31832A – White Bluff, Unit 2 - Low NOx Burners and Over Fired Air 

General Information 

Project Type – Compliance study for Lake Catherine Unit 4 and White Bluff Station Units 1&2. 

Type of estimates – Conceptual Cost Estimate for the SCR Case and Order of Magnitude Cost Estimates for all 

other cases. 

Project location – White Bluff: Close to Pine Bluff, Arkansas; Lake Catherine: Close to Mahern, AR 

MW rating: White Bluff Unit 1: 815 MW, Unit 2: 844 MW; Lake Catherine Unit 4: 558 MW 

Unique site issues – Existing Site. 

Contracting strategy – Multiple Lump Sum. 

The major components of the capital cost consist of equipment, field materials and supplies, direct labor, indirect 

field labor, and indirect construction costs. The capital cost was determined through the process of estimating 

the cost of equipment, components and bulk quantity. 

The cost estimates are based largely on Sargent & Lundy LLC experience on similar projects. Detailed 

engineering has not been performed to firm up the project details, and specific site characteristics have not been 

fully analyzed. We have attempted to assign allowances where necessary to cover issues that are likely to arise 

but are not clearly quantified at this time. 

Estimate Development

The cost estimates for the Low NOx Burners/Over Fired Air cases were based on a previous estimate prepared 

in 2011. Equipment costs were escalated to current pricing level. Also, material and labor have been updated to 

2012 pricing. 

Cost estimates for the SNCR technology (two cases) were based on budgetary quotes received from 

engineering and on previous estimates. 

The cost estimates for the White Bluff SCR was mainly based on similar size and scope cost estimates from 

other projects and structural takeoffs from engineering. All equipment common to both Units was divided evenly 

between the two estimates. 

The cost estimate for Lake Catherine SCR was adjusted from another cost estimate for a gas fired power station. 

White Bluff’s auxiliary boiler cost estimate for Low NOx Burners/Over Fired Air/Flue Gas Recirculation was also 

adjusted from a similar project. 

Pricing and Quantities

The data used to develop these estimates is based on using material and equipment types and sizes typically 

used in a power plant. 

Equipment and material costs were estimated on the basis of S&L in house data, vendor catalogs, industry 

publications and other related projects. In most cases, the costs for bulk materials and equipment were derived 

from recent vendor or manufacturer’s quote for similar items on other projects. Where actual or specific 

information regarding equipment specifications was available, that information was used to size and quantify 

material and equipment requirements. Where information was not furnished or was not adequate, requirements 

were assumed and estimated based on information available from project estimates of similar type and size. 

Page 1 of 3 
Client:  Entergy  Preparer:  A Hays 

Station:  White Bluff/Lake Catherine  Date:         09/04/2012 (Rev 0) 

Project No.: 13027‐001 

 

Quantities contained herein are intended to be reasonable and representative of projects of this type. All 

quantity data was developed internally by S&L. Quantities were developed based on project experience of a 

plant of comparable size and then adjusted based on actual size and capacity differences and also taking into 

consideration the specific site layout based on the general arrangement drawing. While project specifics will 

certainly have an impact on these quantities, we feel they are appropriate for a study at this level. 

Labor Wage Rates

Labor Profile – Union 

Labor wage rate selected for the estimate - 2012 Union rates for Pine Bluff, Arkansas. Base craft rates are as 

published in RS Means Labor Rates for the Construction Industry, 2012 Edition. The craft rates are then 

incorporated into work crews appropriate for the activities by adding allowances for small tools, construction 

equipment, insurance, and site overheads to arrive at crew rates detailed in the cost estimate. A 1.15 regional 

labor productivity multiplier is included based on the Compass International Global Construction Yearbook. 

Labor Work Schedule and Incentives - Assumed 5x10 work week for regular work and 7x10 work week for 

outage work. 10% of the work is assumed to be outage related. 

 

Project Direct & Construction Indirect Costs

The estimate is constructed in such a manner where most of the direct construction costs are determined directly 

and several direct construction cost accounts are determined indirectly by taking a percentage of the directly 

determined costs and are identified as “Variable Accounts”. These percentages are based on our experience 

with similar type and size projects. Sales tax is specific to location. Listed below are the variable accounts. 

 Cost of overtime – 5-10’s Hour Days and Outage Work at a 7-10 Schedule 

 Subsistence (per diem) – not included 

 Consumables – 0.5% of material and labor 

 Freight on Equipment - included with equipment cost 

 Freight on Material @ 5% of material 

 Spare Parts – included with equipment costs 

 Contractors G&A Expense @ 10% 

 Contractors Profit @ 5% 

Project Indirect Costs

Included are the following: 

 Engineering, Procurement & Project Services varied depending on the size of the project estimated. 

o 31813A @ 19% of construction cost 

o 31814A @ 8% of construction cost 

o 31815A @ 8% of construction cost 

o 31816A @ 16% of construction cost 

o 31817A @ 6% of construction cost 

o 31818A @ 6% of construction cost 

o 31819A @ 8% of construction cost 

o 31820A @ 12% of construction cost 

o 31832A @ 16% of construction cost 

 Construction Management varied depending on the size of the project estimated. 

o 31813A @ 6% of construction cost 

o 31814A @ 3% of construction cost 

o 31815A @ 2% of construction cost 

o 31816A @ 6% of construction cost 

o 31817A @ 2% of construction cost 

Page 2 of 3 
Client:  Entergy  Preparer:  A Hays 

Station:  White Bluff/Lake Catherine  Date:         09/04/2012 (Rev 0) 

Project No.: 13027‐001 

 

Page 3 of 3 

o 31818A @ 2% of construction cost 

o 31819A @ 2% of construction cost 

o 31820A @ 0% of construction cost 

o 31832A @ 6% of construction cost 

 Craft start-up and commission support @ 1% of construction cost 

 General Owner’s Costs, including Owners Engineering & Bond Fees – not included 

 EPC Fee – not included 

These percentages are based on our experience with similar type and size projects. 

Escalation

Not included. 

Contingency 

The contingency rates vary for each project based on the project’s size. The rates are based on past history of 

similar projects. This rate relates to pricing and quantity variation in the specific scope estimated. The 

contingency does not cover new scope outside of what has been estimated, only the variation in the defined 

scope. This is a composite rate and already takes into account the plus and minuses of expected actual costs. 

The rate does not represent the high range of all costs, nor is it expected that the project will experience all 

actual costs be realized at the maximum value of their range of variation. 

Exclusions

There are items that have been specifically excluded from the estimate. In order to establish the overall project 

costs, the following items must also be accounted for. This list is for information only and is not intended to be all 

inclusive. 

 Permitting costs 

 Rock excavation 

 Remediation of soil for hazardous materials 

 Power outage cost during construction 

Assumptions

 No rock excavation, no dewatering 

 Assumed that asbestos removal or lead paint abatement will not be required. 

 No obstruction for the ammonia pipe routing. 6” clearing & grubbing of existing terrain is included, no 

tree removal. 

 Directional boring underneath the existing railroad tracks is included, but with no major interferences or 

obstructions. 

 Electrical equipment and wiring installation is based on non-hazardous location. 

 Adjustments for plant unit size were made based on good engineering practice. Actual design and 

quantities may be significantly different than the quantities shown in the estimates. 
ESTIMATE NO.: 31813A2 ENTERGY - LAKE CATHERINE

PROJECT NO.: 13027-001 LOW NOX BURNERS AND OVERFIRE AIR SYSTEMS - UNIT 4

ISSUE DATE: CONCEPTUAL ESTIMATE

PREP./REV.: ADH/

APPROVED: 

Estimate Totals

Description Amount Totals

Labor 331,677

Material 125,263

Subcontract 2,850,000

Equipment

Other 2,000,000

5,306,940 5,306,940 USD

91-1 Scaffolding 46,000

91-2 OT Working 5-10 Hour Days 41,000

91-3 OT Working 7-10 Hr Days

91-4 Per Diem

91-5 Consumables 2,000

91-6 Freight on Equipment

91-7 Freight on Special Equip.

91-8 Freight on Material 6,000

91-9 Freight on Process Equip. 100,000

91-10 Sales Tax

91-11 Contractor's G&A Expense 65,000

91-12 Contractor's Profit 32,000

292,000 5,598,940 USD

93-1 EP&P Services 1,064,000

93-2 CM Support 168,000

93-3 Start-Up/Commissioning 56,000

93-4 Start-Up/Spare Parts

93-5 Excess Liability Insur.

93-6 Sales Tax On Indirects

93-7 Owners Cost

93-8 EPC Fee

1,288,000 6,886,940 USD

94-1 Contingency on Equipment

94-2 Contingency on Engr Equip

94-3 Contingency on Material 50,000

94-4 Contingency on Labor 145,000

94-5 Contingency on Sub. 713,000

94-6 Contingency on Equipment 525,000

94-7 Contingency on Indirect 386,000

1,819,000 8,705,940 USD

96-1 Escalation on Equipment

96-2 Escalation on Engr Equip

96-3 Escalation on Material

96-4 Escalation on Labor

96-5 Escalation on Sub.

96-6 Escalation on Process Equ

96-7 Escalation on Indirect

8,705,940 USD

98 - Interest During Constr

8,705,940 USD

Total 8,705,940 USD

PRINT DATE 8/23/2012 4:24 PM Page 3

\\sltimberline\estimating\PROJECTS\ENTERGY\Lake Catherine - Confidential
ESTIMATE NO.: 31814A ENTERGY - LAKE CATHERINE

PROJECT NO.: 13027-001 SCR SYSTEM - UNIT 4ISSUE DATE: 8/31/2012 CONCEPTUAL ESTIMATEPREP./REV.: ADH/APPROVED: MNO

Estimate Totals

Description Amount Totals

Labor 19,780,000Material 15,815,652Subcontract 2,590,000EquipmentOther 8,290,000

46,475,652 46,475,652 USD

91-1 Scaffolding91-2 OT Working 5-10 Hour Days91-3 OT Working 7-10 Hr Days91-4 Per Diem91-5 Consumables91-6 Freight on Equipment91-7 Freight on Special Equip.91-8 Freight on Material91-9 Freight on Process Equip.91-10 Sales Tax91-11 Contractor's G&A Expense91-12 Contractor's Profit

46,475,652 USD

93-1 EP&P Services 3,718,10093-2 CM Support 1,394,30093-3 Start-Up/Commissioning 464,80093-4 Start-Up/Spare Parts93-5 Excess Liability Insur.93-6 Sales Tax On Indirects93-7 Owners Cost93-8 EPC Fee

5,577,200 52,052,852 USD

94-1 Contingency on Equipment94-2 Contingency on Engr Equip94-3 Contingency on Material 2,372,40094-4 Contingency on Labor 2,967,00094-5 Contingency on Sub. 388,50094-6 Contingency on Equipment 1,243,50094-7 Contingency on Indirect 836,600

7,808,000 59,860,852 USD

96-1 Escalation on Equipment96-2 Escalation on Engr Equip96-3 Escalation on Material96-4 Escalation on Labor96-5 Escalation on Sub.96-6 Escalation on Process Equ96-7 Escalation on Indirect

59,860,852 USD

98 - Interest During Constr

59,860,852 USD

Total 59,860,852 USD

PRINT DATE 9/19/2012 10:49 AM Page 3\\sltimberline\estimating\PROJECTS\ENTERGY\Lake Catherine - Confidential
ESTIMATE NO.: 31815A ENTERGY - LAKE CATHERINE

PROJECT NO.: 13027-001 SNCR SYSTEM - UNIT 4

ISSUE DATE: 9/7/2012 CONCEPTUAL ESTIMATE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Amount Totals

Labor 2,629,958

Material 1,083,165

Subcontract 80,600

Equipment

Other 6,193,056

9,986,779 9,986,779 USD

91-1 Scaffolding 445,600

91-2 OT Working 5-10 Hour Days 311,700

91-3 OT Working 7-10 Hr Days 99,200

91-4 Per Diem

91-5 Consumables 18,600

91-6 Freight on Equipment

91-7 Freight on Special Equip.

91-8 Freight on Material 54,200

91-9 Freight on Process Equip.

91-10 Sales Tax

91-11 Contractor's G&A Expense 458,800

91-12 Contractor's Profit 229,500

1,617,600 11,604,379 USD

93-1 EP&P Services 928,400

93-2 CM Support 232,100

93-3 Start-Up/Commissioning 116,000

93-4 Start-Up/Spare Parts

93-5 Excess Liability Insur.

93-6 Sales Tax On Indirects

93-7 Owners Cost

93-8 EPC Fee

1,276,500 12,880,879 USD

94-1 Contingency on Equipment

94-2 Contingency on Engr Equip

94-3 Contingency on Material 390,000

94-4 Contingency on Labor 1,209,300

94-5 Contingency on Sub. 24,200

94-6 Contingency on Equipment 619,300

94-7 Contingency on Indirect 383,000

2,625,800 15,506,679 USD

96-1 Escalation on Equipment

96-2 Escalation on Engr Equip

96-3 Escalation on Material

96-4 Escalation on Labor

96-5 Escalation on Sub.

96-6 Escalation on Process Equ

96-7 Escalation on Indirect

15,506,679 USD

98 - Interest During Constr

15,506,679 USD

Total 15,506,679 USD

PRINT DATE 9/7/2012 3:39 PM Page 4

\\sltimberline\estimating\PROJECTS\ENTERGY\Lake Catherine - Confidential
ESTIMATE NO.: 31816A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 LOW NOX BURNERS AND OVERFIRE AIR SYSTEMS - UNIT 1

ISSUE DATE: 8/31/2012 CONCEPTUAL ESTIMATE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Amount Totals

Labor 653,648

Material 306,347

Subcontract 3,700,000

Equipment

Other

4,659,995 4,659,995 USD

91-1 Scaffolding 48,000

91-2 OT Working 5-10 Hour Days 77,000

91-3 OT Working 7-10 Hr Days 24,000

91-4 Per Diem

91-5 Consumables 5,000

91-6 Freight on Equipment

91-7 Freight on Special Equip.

91-8 Freight on Material 15,000

91-9 Freight on Process Equip.

91-10 Sales Tax

91-11 Contractor's G&A Expense 112,000

91-12 Contractor's Profit 55,000

336,000 4,995,995 USD

93-1 EP&P Services 799,000

93-2 CM Support 300,000

93-3 Start-Up/Commissioning 50,000

93-4 Start-Up/Spare Parts

93-5 Excess Liability Insur.

93-6 Sales Tax On Indirects

93-7 Owners Cost

93-8 EPC Fee

1,149,000 6,144,995 USD

94-1 Contingency on Equipment

94-2 Contingency on Engr Equip

94-3 Contingency on Material 110,000

94-4 Contingency on Labor 279,000

94-5 Contingency on Sub. 925,000

94-6 Contingency on Equipment

94-7 Contingency on Indirect 345,000

1,659,000 7,803,995 USD

96-1 Escalation on Equipment

96-2 Escalation on Engr Equip

96-3 Escalation on Material

96-4 Escalation on Labor

96-5 Escalation on Sub.

96-6 Escalation on Process Equ

96-7 Escalation on Indirect

7,803,995 USD

98 - Interest During Constr

7,803,995 USD

Total 7,803,995 USD

PRINT DATE 8/31/2012 10:32 AM Page 3

\\sltimberline\estimating\PROJECTS\ENTERGY\White Bluff - Confidential
ESTIMATE NO.: 31819A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 SNCR SYSTEM - UNIT 1

ISSUE DATE: 9/7/2012 CONCEPTUAL ESTIMATE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Amount Totals

Labor 2,255,791

Material 1,089,242

Subcontract 68,100

Equipment

Other 1,948,100

5,361,233 5,361,233 USD

91-1 Scaffolding 368,000

91-2 OT Working 5-10 Hour Days 267,300

91-3 OT Working 7-10 Hr Days 85,100

91-4 Per Diem

91-5 Consumables 16,700

91-6 Freight on Equipment

91-7 Freight on Special Equip.

91-8 Freight on Material 54,500

91-9 Freight on Process Equip.

91-10 Sales Tax

91-11 Contractor's G&A Expense 408,200

91-12 Contractor's Profit 204,100

1,403,900 6,765,133 USD

93-1 EP&P Services 541,200

93-2 CM Support 135,300

93-3 Start-Up/Commissioning 67,700

93-4 Start-Up/Spare Parts

93-5 Excess Liability Insur.

93-6 Sales Tax On Indirects

93-7 Owners Cost

93-8 EPC Fee

744,200 7,509,333 USD

94-1 Contingency on Equipment

94-2 Contingency on Engr Equip

94-3 Contingency on Material 392,100

94-4 Contingency on Labor 1,032,500

94-5 Contingency on Sub. 20,400

94-6 Contingency on Equipment 194,800

94-7 Contingency on Indirect 223,300

1,863,100 9,372,433 USD

96-1 Escalation on Equipment

96-2 Escalation on Engr Equip

96-3 Escalation on Material

96-4 Escalation on Labor

96-5 Escalation on Sub.

96-6 Escalation on Process Equ

96-7 Escalation on Indirect

9,372,433 USD

98 - Interest During Constr

9,372,433 USD

Total 9,372,433 USD

PRINT DATE 9/7/2012 3:11 PM Page 4

\\sltimberline\estimating\PROJECTS\ENTERGY\White Bluff - Confidential
ESTIMATE NO.: 31817A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 SCR - UNIT 1

ISSUE DATE: 8/31/2012 CONCEPTUAL ESTIMATE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Amount Totals

Labor 56,778,212

Material 34,013,262

Subcontract 8,156,000

Equipment

Other 21,324,260

120,271,734 120,271,734 USD

91-1 Scaffolding 2,270,000

91-2 OT Working 5-10 Hour Days 6,730,000

91-3 OT Working 7-10 Hr Days 2,142,000

91-4 Per Diem

91-5 Consumables 454,000

91-6 Freight on Equipment

91-7 Freight on Special Equip.

91-8 Freight on Material 1,701,000

91-9 Freight on Process Equip.

91-10 Sales Tax

91-11 Contractor's G&A Expense 10,238,000

91-12 Contractor's Profit 5,120,000

28,655,000 148,926,734 USD

93-1 EP&P Services 8,936,000

93-2 CM Support 2,979,000

93-3 Start-Up/Commissioning 1,489,000

93-4 Start-Up/Spare Parts

93-5 Excess Liability Insur.

93-6 Sales Tax On Indirects

93-7 Owners Cost

93-8 EPC Fee

13,404,000 162,330,734 USD

94-1 Contingency on Equipment

94-2 Contingency on Engr Equip

94-3 Contingency on Material 8,163,000

94-4 Contingency on Labor 15,726,000

94-5 Contingency on Sub. 1,631,000

94-6 Contingency on Equipment 4,265,000

94-7 Contingency on Indirect 2,681,000

32,466,000 194,796,734 USD

96-1 Escalation on Equipment

96-2 Escalation on Engr Equip

96-3 Escalation on Material

96-4 Escalation on Labor

96-5 Escalation on Sub.

96-6 Escalation on Process Equ

96-7 Escalation on Indirect

194,796,734 USD

98 - Interest During Constr

194,796,734 USD

Total 194,796,734 USD

PRINT DATE 8/31/2012 10:50 AM Page 3

\\sltimberline\estimating\PROJECTS\ENTERGY\White Bluff - Confidential
ESTIMATE NO.: 31832A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 LOW NOX BURNERS AND OVERFIRE AIR SYSTEMS - UNIT 2

ISSUE DATE: 8/31/2012 CONCEPTUAL ESTIMATE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Amount Totals

Labor 653,648

Material 306,347

Subcontract 3,700,000

Equipment

Other 2,600,000

7,259,995 7,259,995 USD

91-1 Scaffolding 48,000

91-2 OT Working 5-10 Hour Days 77,000

91-3 OT Working 7-10 Hr Days 24,000

91-4 Per Diem

91-5 Consumables 5,000

91-6 Freight on Equipment

91-7 Freight on Special Equip.

91-8 Freight on Material 15,000

91-9 Freight on Process Equip.

91-10 Sales Tax

91-11 Contractor's G&A Expense 112,000

91-12 Contractor's Profit 55,000

336,000 7,595,995 USD

93-1 EP&P Services 1,215,000

93-2 CM Support 456,000

93-3 Start-Up/Commissioning 76,000

93-4 Start-Up/Spare Parts

93-5 Excess Liability Insur.

93-6 Sales Tax On Indirects

93-7 Owners Cost

93-8 EPC Fee

1,747,000 9,342,995 USD

94-1 Contingency on Equipment

94-2 Contingency on Engr Equip

94-3 Contingency on Material 110,000

94-4 Contingency on Labor 279,000

94-5 Contingency on Sub. 925,000

94-6 Contingency on Equipment 650,000

94-7 Contingency on Indirect 524,000

2,488,000 11,830,995 USD

96-1 Escalation on Equipment

96-2 Escalation on Engr Equip

96-3 Escalation on Material

96-4 Escalation on Labor

96-5 Escalation on Sub.

96-6 Escalation on Process Equ

96-7 Escalation on Indirect

11,830,995 USD

98 - Interest During Constr

11,830,995 USD

Total 11,830,995 USD

PRINT DATE 8/31/2012 10:37 AM Page 3

\\sltimberline\estimating\PROJECTS\ENTERGY\White Bluff - Confidential
ESTIMATE NO.: 31840A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 SNCR SYSTEM - UNIT 2

ISSUE DATE: 9/7/2012 CONCEPTUAL ESTIMATE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Amount Totals

Labor 2,255,791

Material 1,089,242

Subcontract 68,100

Equipment

Other 1,948,100

5,361,233 5,361,233 USD

91-1 Scaffolding 368,000

91-2 OT Working 5-10 Hour Days 267,300

91-3 OT Working 7-10 Hr Days 85,100

91-4 Per Diem

91-5 Consumables 16,700

91-6 Freight on Equipment

91-7 Freight on Special Equip.

91-8 Freight on Material 54,500

91-9 Freight on Process Equip.

91-10 Sales Tax

91-11 Contractor's G&A Expense 408,200

91-12 Contractor's Profit 204,100

1,403,900 6,765,133 USD

93-1 EP&P Services 541,200

93-2 CM Support 135,300

93-3 Start-Up/Commissioning 67,700

93-4 Start-Up/Spare Parts

93-5 Excess Liability Insur.

93-6 Sales Tax On Indirects

93-7 Owners Cost

93-8 EPC Fee

744,200 7,509,333 USD

94-1 Contingency on Equipment

94-2 Contingency on Engr Equip

94-3 Contingency on Material 392,100

94-4 Contingency on Labor 1,032,500

94-5 Contingency on Sub. 20,400

94-6 Contingency on Equipment 194,800

94-7 Contingency on Indirect 223,300

1,863,100 9,372,433 USD

96-1 Escalation on Equipment

96-2 Escalation on Engr Equip

96-3 Escalation on Material

96-4 Escalation on Labor

96-5 Escalation on Sub.

96-6 Escalation on Process Equ

96-7 Escalation on Indirect

9,372,433 USD

98 - Interest During Constr

9,372,433 USD

Total 9,372,433 USD

PRINT DATE 9/7/2012 3:24 PM Page 4

\\sltimberline\estimating\PROJECTS\ENTERGY\White Bluff - Confidential
ESTIMATE NO.: 31818A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 SCR - UNIT 2

ISSUE DATE: CONCEPTUAL ESTIMATE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Amount Totals

Labor 48,597,255

Material 26,751,692

Subcontract 6,577,640

Equipment

Other 21,324,260

103,250,847 103,250,847 USD

91-1 Scaffolding 1,884,000

91-2 OT Working 5-10 Hour Days 5,759,000

91-3 OT Working 7-10 Hr Days 1,834,000

91-4 Per Diem

91-5 Consumables 377,000

91-6 Freight on Equipment

91-7 Freight on Special Equip.

91-8 Freight on Material 1,338,000

91-9 Freight on Process Equip.

91-10 Sales Tax

91-11 Contractor's G&A Expense 8,520,000

91-12 Contractor's Profit 4,261,000

23,973,000 127,223,847 USD

93-1 EP&P Services 7,633,000

93-2 CM Support 2,544,000

93-3 Start-Up/Commissioning 1,272,000

93-4 Start-Up/Spare Parts

93-5 Excess Liability Insur.

93-6 Sales Tax On Indirects

93-7 Owners Cost

93-8 EPC Fee

11,449,000 138,672,847 USD

94-1 Contingency on Equipment

94-2 Contingency on Engr Equip

94-3 Contingency on Material 6,421,000

94-4 Contingency on Labor 13,444,000

94-5 Contingency on Sub. 1,316,000

94-6 Contingency on Equipment 4,265,000

94-7 Contingency on Indirect 2,290,000

27,736,000 166,408,847 USD

96-1 Escalation on Equipment

96-2 Escalation on Engr Equip

96-3 Escalation on Material

96-4 Escalation on Labor

96-5 Escalation on Sub.

96-6 Escalation on Process Equ

96-7 Escalation on Indirect

166,408,847 USD

98 - Interest During Constr

166,408,847 USD

Total 166,408,847 USD

PRINT DATE 8/31/2012 10:45 AM Page 3

\\sltimberline\estimating\PROJECTS\ENTERGY\White Bluff - Confidential
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 3 

APPENDIX B 

1. ESTIMATED PROJECT SCHEDULES 
....Activity ID Activity Name Org Dur

(months)

Entergy - NOx Strategy Study - Aux Boiler (LNB/OFA/FGR)... 15m

Permitting 12m

A1000 Project Authorization 0mA1010 Air Permit - Prepare/Review/Approve 12m

Engineering 8m

A1020 Engineering 8m

Procurement of Major Equipment 6m

A1030 LNB/OFA Spec - Prep/Bid/Eval/Award 3mA1070 GWC Spec - Prep/Bid/Eval/Award 3m

Vendor Engineering/Fab/Delivery 5m

A1040 LNB/OFA Vendor Engineering/Fabrication/Delivery 5m

Installation 1m

A1050 Installation 1m

Commissioning & Start-Up 2m

A1060 Commissioning & Start-Up 2m

1 2 3 4 5 6 7 8 9 10 

Month

Run Date: 09-17-12 NOx Control Technology Cost and Performance Study for

Entergy Services, Inc. White Bluff and Lake Catherine

Aux Boiler Low NOx Burner/Over-Fire Air/Flue Gas Recirculation (LNB/OFA/FGR) 
....Activity ID Activity Name Org Dur

(months)

Entergy - NOx Strategy Study - Neural Network 24m

Permitting 8m

A1000 Project Authorization 0mA1010 Air Permit - Prepare/Review/Approve 8m

Engineering 3m

A1020 Engineering 3m

Procurement of Major Equipment 3m

A1030 Neural Network Spec - Prep/Bid/Eval/Award 3m

Vendor Engineering/Fab/Delivery 6m

A1040 NN Vendor Engineering/Fabrication/Delivery 6m

Installation 1m

A1050 Installation 1m

Commissioning & Start-Up 12m

A1060 Commissioning & Start-Up 12m

-1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 1

Month

Run Date: 09-17-12 NOx Control Technology Cost and Performance Study for

Entergy Services, Inc. White Bluff and Lake Catherine

Neural Network 
....Activity ID Activity Name Org Dur

(months)

Entergy - NOx Strategy Study - Low NOx Burners/Over Fire Air (LNB/OFA) ... 19m

Permitting 12m

A1000 Project Authorization 0mA1010 Air Permit - Prepare/Review/Approve 12m

Engineering 8m

A1020 Engineering 8m

Procurement of Major Equipment 7m

A1030 LNB/OFA Spec - Prep/Bid/Eval/Award 3mA1070 GWC Spec - Prep/Bid/Eval/Award 3m

Vendor Engineering/Fab/Delivery 6m

A1040 LNB/OFA Vendor Engineering/Fabrication/Delivery 6m

Installation 3m

A1050 Installation 3m

Commissioning & Start-Up 4m

A1060 Commissioning & Start-Up 4m

1 2 3 4 5 6 7 8 9 10 11 12 13 

Month

Run Date: 09-17-12 NOx Control Technology Cost and Performance Study for

Entergy Services, Inc. White Bluff and Lake Catherine

Low NOx Burners/Over-Fire Air (LNB/OFA) 
....Activity ID Activity Name Org Dur

(months)

Entergy - NOx Strategy Study - Induced Flue Gas Recirculation (IFGR) ir... 17m

Permitting 2m

A1000 Project Authorization 0mA1010 Air Permit - Prepare/Review/Approve 2m

Engineering 9m

A1020 BOP Engineering 9m

Procurement of Major Equipment 6m

A1140 FGR Duct Procurement Spec - Prep/Bid/Eval/Award 3mA1030 Mech Install Spec - Prep/Bid/Eval/Award 3mA1120 Elec Install Spec - Prep/Bid/Eval/Award 3m

Vendor Engineering/Fab/Delivery 6m

A1040 FGR Duct Vendor Engineering/Fabrication/Delivery 6m

Installation 4m

A1050 Installation 4m

Commissioning & Start-Up 2m

A1060 Commissioning & Start-Up 2m

1 2 3 4 5 6 7 8 9 10 11 

Month

Run Date: 09-17-12 NOx Control Technology Cost and Performance Study for

Entergy Services, Inc. White Bluff and Lake Catherine

Induced Flue Gas Recirculation (IFGR) 
....Activity ID Activity Name Org Dur

(months)

Entergy - NOx Strategy Study - Flue Gas Recirculation (FGR) on ... 22m

Permitting 8m

A1000 Project Authorization 0mA1010 Air Permit - Prepare/Review/Approve 8m

Engineering 10m

A1020 BOP Engineering 10m

Procurement of Major Equipment 6m

A1150 FGR Fan Procurement Spec - Prep/Bid/Eval/Award 3mA1140 FGR Duct Procurement Spec - Prep/Bid/Eval/Award 3mA1030 Mech Install Spec - Prep/Bid/Eval/Award 3mA1120 Elec Install Spec - Prep/Bid/Eval/Award 3m

Vendor Engineering/Fab/Delivery 10m

A1040 FGR Duct Vendor Engineering/Fabrication/Delivery 6mA1160 FGR Fan Vendor Engineering/Fabrication/Delivery 10m

Installation 5m

A1050 Installation 5m

Commissioning & Start-Up 2m

A1060 Commissioning & Start-Up 2m

1 2 3 4 5 6 7 8 9 10 11 12 13 14 

Month

Run Date: 09-17-12 NOx Control Technology Cost and Performance Study for

Entergy Services, Inc. White Bluff and Lake Catherine

Flue Gas Recirculation (FGR) 
....Activity ID Activity Name Org Dur

(months)

Entergy - NOx Strategy Study - Selective Non-Catalytic Reduction (SNCR) tic ... 16m

Permitting 12m

A1000 Project Authorization 0mA1010 Air Permit - Prepare/Review/Approve 12m

Engineering 8m

A1020 BOP Engineering 8m

Procurement of Major Equipment 6m

A1030 SNCR Spec - Prep/Bid/Eval/Award 3mA1070 Civil/Structural Installation Spec - Prep/Bid/Eval/Award 3mA1080 Mech Installation Spec - Prep/Bid/Eval/Award 3mA1090 Elec/I&C Installation Spec - Prep/Bid/Eval/Award 3m

Vendor Engineering/Fab/Delivery 6m

A1040 SNCR Vendor Engineering/Fabrication/Delivery 6m

Installation 3m

A1050 Installation 3m

Commissioning & Start-Up 1m

A1060 Commissioning & Start-Up 1m

1 2 3 4 5 6 7 8 9 10 

Month

Run Date: 09-14-12 NOx Control Technology Cost and Performance Study for

Entergy Services, Inc. White Bluff and Lake Catherine

Selective Non-Catalytic Reduction (SNCR) 
....Activity ID Activity Name Org Dur

(months)

Entergy - NOx Strategy Study - Selective Catalytic Reduction (SCR) Red... 32m

Permitting 12m

A1000 Project Authorization 0mA1010 Air Permit - Prepare/Review/Approve 12m

Engineering 16m

A1020 BOP Engineering 16m

Procurement of Major Equipment 12m

A1140 Ammonia Injection System Procurement Spec - Prep/Bid/Eval/Award 3mA1150 Catalyst Procurement Spec - Prep/Bid/Eval/Award 3mA1170 Fan Spec - Prep/Bid/Eval/Award 3mA1190 Ductwork Spec - Prep/Bid/Eval/Award 3mA1130 Structural Steel Spec - Prep/Bid/Eval/Award 3mA1030 Mech Install Spec - Prep/Bid/Eval/Award 3mA1120 Elec Install Spec - Prep/Bid/Eval/Award 3m

Vendor Engineering/Fab/Delivery 16m

A1160 Catalyst Vendor Engineering/Fabrication/Delivery 12mA1210 Structural Steel Vendor Engineering/Fabrication/Delivery 7mA1200 Ductwork Vendor Engineering/Fabrication/Delivery 10mA1040 Ammonia Injection System Vendor Engineering/Fabrication/Delivery 16mA1180 Fan Vendor Engineering/Fabrication/Delivery 12m

Installation 18m

A1050 Installation 18m

Commissioning & Start-Up 2m

A1060 Commissioning & Start-Up 2m

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 1

Mo

Run Date: 09-17-12 NOx Control Technology Cost and Performance Study for

Entergy Services, Inc. White Bluff and Lake Catherine

Selective Catalytic Reduction (SCR) 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 4 

APPENDIX C 

1. OPERATING AND MAINTENANCE COST ESTIMATES 
NOx Control Technology Cost and Performance Study NOX Compliance Costs 

Unit Name White Bluff 1

Unit Data

Size (Gross kW) 815,000 Aq.Ammonia $/t $700Average NOx Emission Rate (lb/MMBtu at full load) 0.33 An.Ammonia $/t $400

Nominal Max. Boiler Heat Input (mmBtu/hr) 8,950.0 Urea $/t $350Avg. Heat Rate (Btu/kwh) 10,981.6 N/F-T Urea $/t $618Aux. Power (kw) - Coal Cost, $/Mbtu 2.650Est. Capacity Factor (%) 76.00Boiler Type T/F

Water Cost, $/1000 gal (3) 2

Boiler Eff. (%) 84 Electricity, $/MWh 41.50Estimated NOx, tons/day Max 26.936Emission Limit, tons -

NOx Sales/Buy rate, $/ton -

Fuel - PRB

Seasonal Days 153

Basis 0

Analysis - Enter "0" for Annual and 1 for Seasonal

CF For Variable O&M 76.00

Estimated Reduction 

from Baseline

Emission Rate After 

Control

Tons of NOx Emission, 

Seasonal/Annual

Tons of NOx Removed, 

season/annual Estimated Capital C

Technology % (lb/mmBtu) tons tons $/kW 

LNB + OFA (Note 5) 54.5 0.15 4,469 5,363 9.6 $7Neural Net 10.0 0.30 8,848 983 0.3 $Full SNCR 26.5 0.24 7,229 2,602 11.5 $9LNB+OFA+Full SNCR 61.4 0.13 3,799 6,033 20.0 $1LNB+OFA+Full SCR 83.3 0.055 1,639 8,193 248.6 $20

(1) Aux. Power cost is calculated based on variation in capacity factor(2) Assumed water cost of $2/1000 gallons.(3) Assumed that 15% urea will be used for SNCR technology.(4) Assumed that initial catalyst life is 12,000 hours (5) LNB/OFA material already purchased for Unit 1. The total cost to Entergy would be the same for Unit 1 as shown for Unit 2.(6) For SCR technology, the variable O&M costs are based on operating at NOx outlet emissions marginally below the compliance emission rate.

Reagent Costs

Entergy - NOX Compliance Cost Worksheet - 051613/White Bluff 1 
NOx Control Technology Cost and Performance Study NOX Compliance Costs 

Unit Name White Bluff 2

Unit Data

Size (Gross kW) 844,000 Aq.Ammonia $/t $700Average NOx Emission Rate (lb/MMBtu at full load) 0.39 An.Ammonia $/t $400

Nominal Max. Boiler Heat Input (mmBtu/hr) 8,950.0 Urea $/t $350Avg. Heat Rate (Btu/kwh) 10,604.3 N/F-T Urea $/t $618Aux. Power (kw) - Coal Cost, $/Mbtu 2.650Est. Capacity Factor (%) 76.00Boiler Type T/F

Water Cost, $/1000 gal (3) 2

Boiler Eff. (%) 84 Electricity, $/MWh 41.50Estimated NOx, tons/day Max 31.833Emission Limit, tons -

NOx Sales/Buy rate, $/ton -

Fuel - PRB

Seasonal Days 153

Basis 0

Analysis - Enter "0" for Annual and 1 for Seasonal

CF For Variable O&M 76.00

Estimated Reduction 

from Baseline

Emission Rate After 

Control

Tons of NOx Emission, 

Seasonal/Annual

Tons of NOx Removed, 

season/annual Estimated Capital C

Technology % (lb/mmBtu) tons tons $/kW 

LNB + OFA 61.5 0.15 4,469 7,150 14.0 $1Neural Net 10.0 0.35 10,457 1,162 0.3 $Full SNCR 26.5 0.29 8,544 3,076 11.1 $9LNB+OFA+Full SNCR 67.3 0.13 3,799 7,821 24.1 $2LNB+OFA+Full SCR 85.9 0.055 1,639 9,981 211.2 $17

(1) Aux. Power cost is calculated based on variation in capacity factor(2) Assumed water cost of $2/1000 gallons.(3) Assumed that 15% urea will be used for SNCR technology.(4) Assumed that initial catalyst life is 12,000 hours (5) For SCR technology, the variable O&M costs are based on operating at NOx outlet emissions marginally below the compliance emission rate.

Reagent Costs

Entergy - NOX Compliance Cost Worksheet - 051613/White Bluff 2 
NOx Control Technology Cost and Performance Study NOX Compliance Costs 

Unit name Lake Catherine Unit 4

Unit Data

Size (Gross kW) 558,000 Aq.Ammonia $/t $700Average NOx Emission Rate (lb/MMBtu) 0.4825 An.Ammonia $/t $400 

Nominal Max. Boiler Heat Input (mmBtu/hr) 5,850.0 Urea $/t $350 Avg. Heat Rate (Btu/kwh) 10,483.9 N/F-T Urea $/t $618 Aux. Power (kw) - Gas Cost, $/MBtu 4.900 Est. Capacity Factor (%) 10.00

Water Cost, $/1000 gal (3) 2

Boiler Type T/F Electricity, $/MWh 41.50

Boiler Eff. (%) 82Estimated NOx, tons/day Max 3.387Emission Limit, tons -

NOx Sales/Buy rate, $/ton 2500.0

Fuel Gas

Seasonal Days 153

Basis 0

Analysis - Enter "0" for Annual and 1 for Seasonal

CF For Variable O&M 10.00

Estimated Reduction 

from Baseline

Emission Rate After 

Control

Tons of NOx Emission, 

Seasonal/Annual

Tons of NOx Removed, 

season/annual Estimated Capital C

Technology % (lb/mmBtu) tons tons $/kW 

Baseline 0 0.4825

BOOS (at 558 MW) 50.0 0.24 618 618 1.6 $LNB + OFA 60.0 0.19 495 742 15.7 $SCR 90.0 0.05 124 1,113 106.8 $5SNCR 40.0 0.29 742 495 27.8 $1Water Injection 9.1 0.44 1,124 113 3.9 $2IFGR (below 500 MW) 19.0 0.39 1,001 235 3.9 $2FGR 60.0 0.19 495 742 20.6 $1LNB/OFA + SNCR 70.0 0.14 371 865 43.5 $2LNB/OFA + SCR 94.0 0.03 74 1,162 122.5 $6

(1) Aux. Power cost is calculated based on variation in capacity factor(2) Assumed water cost of $2/1000 gallons.(3) Assumed that 15% urea will be used for SNCR technology.(4) Assumed that initial catalyst life is 40,000 hours.(5) Water Injection is used only for trimming at high load. Approximately 66% of Hours are affected.(6) For SCR technology, the variable O&M costs are based on operating at NOx outlet emissions marginally below the compliance emission rate.

Reagent Costs

Entergy - NOX Compliance Cost Worksheet - 051613/LC4 '03 Data 
Entergy Services, Inc. 

White Bluff & Lake Catherine 

Project No. 13027-001 

NOx Control Technology Cost 

and Performance Study 

SL-011439 

Final Report Rev. 4 

5/16/2013 

Page No. 5 

APPENDIX D 

1. BOOS AT FULL UNIT LOAD 
To: DAVID H PARK/Sargentlundy@Sargentlundy, 

Cc:

Bcc:

Subject: Fw: BOOS for NOx Control

From: STEVE M KATZBERGER/Sargentlundy - Thursday 03/28/2013 03:32 PM

From: Stephen Wood [mailto:swood@etecinc.net] 

Sent: Monday, March 25, 2013 2:20 PM

To: HANTZ, JOSEPH

Subject: BOOS for NOx Control

Joe,

The attached PDF file contains background information on utilizing burners out of service for NOx

control, as well as, predicted Lake Catherine Unit 4 burner header pressures and NOx emissions, utilizing

the top burner elevation out of service (4BOOS). If you have any questions, please let me know.

Regards,

Steve Wood

Principal Officer

Entropy Technology & Environmental Consultants, Inc. (ETEC Inc.)

12337 Jones Rd. Suite 414

Houston, TX 77070

Ph: 281-807-7007

Cell: 713-253-8230

Fax: 281-807-1414

Website: www.etecinc.net

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belonging to the ETEC Inc. This e-mail is intended solely for the use of the

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and permanently delete the original and any copy of this e-mail and any

printout. Thank You.

******************************* BOOS for NOx Control.pdf 
Combustion Modification (BOOS) for NOx Control 

Implementation of Burner Out Of Service (BOOS) operation is a practical and cost-effective 

means for achieving staged combustion (i.e., modifying burner stoichoimetry to reduce NOx 

emissions formation) on an existing gas/oil fired electric utility boiler. Utilizing BOOS operation 

for NOx control is well documented in the literature, e.g., EPA 456/F-99-006R "Nitrogen 

Oxides (NOx), Why And How They Are Controlled", November 1999, and EPRI TR-108181 

"Retrofit NOx Control Guidelines for Gas- and Oil-Fired Boilers, Version 2.0", June 1997, 

among numerous others. 

The technique of BOOS operation involves terminating the fuel flow to selected burners on the 

top elevation while leaving the air registers open. The remaining burners operate fuel-rich, 

thereby limiting oxygen availability, lowering peak flame temperatures, and reducing NOx 

formation. The un-reacted products combine with the air from the above terminated-fuel burners 

to complete burnout before exiting the furnace. I have personally been involved with 

implementing BOOS operation on virtually every gas fired electric utility boiler design across 

the country since the mid 1970's. In almost every case, the original "high" burner header pressure 

(BHP) set point had to be increased to accommodate BOOS operation. No adverse operational 

or maintenance problems corresponding to BOOS implementation have been reported. 

BOOS operation can be a very effective NOx reduction technology, depending on the degree of 

staging, as shown for Ninemile Unit 4 (750 mw CE Tangential Fired) in Figure 1. The 

corresponding BOOS pattern is shown in Figure 2. The BHP corresponding to 4BOOS operation 

on Lake Catherine Unit 4 is shown in Figure 3. The "High" BHP set point would need to be 

increased from 42 to 50 psig. The predicted NOx emissions corresponding to 4BOOS operation 

are presented in Figure 4. 
Figure 1- Stoichiometry Modification (BOOS) NOx Reduction 

NM4 4BOOS 

NM4 Baseline 
Figure 2- Ninemile Units 4 and 5 BOOS Pattern 

(Top Elevation Out of Service & Air Registers Open) 

Level 1

Level 5

Level 4

Level 3

Level 2

SW SE NW NE

BOOS BOOS BOOS BOOS
Figure 3- Lake Catherine Unit 4 Burner Header Pressure 

0

5

10

15

20

25

30

35

40

45

0 50 100 150 200 250 300 350 400 450 500 550

BHP, psig

Load, mwn

Lake Catherine Unit 4 Burner Header Pressure

Baseline

4BOOS
Figure 4- Lake Catherine Unit 4 NOx Emissions Prediction 

0

0.1

0.2

0.3

0.4

0.5

0.6

0 100 200 300 400 500 600

NOx, lb/mmbtu

LOAD, MWG

Lake Catherine Unit 4 Predicted NOx with 4BOOS

Baseline

BOOS