## R EVISED 

## BART F IVE 

## F ACTOR 

## A NALYSIS



## L AKE 

## C ATHERINE 

## S TEAM 

## E LECTRIC 

## S TATION



## M ALVERN 

## , A RKANSAS 

## (AFIN 30

- 00011 )

Prepared By:

T RINITY 

### C ONSULTANTS 

### , I NC



### . 201 NW 63rd St., Suite 220 Oklahoma City, Oklahoma 73116
(405) 848

- 3724

T RINITY 

### C ONSULTANTS 

### , I NC



### . 977 Rid ge Drive, Suite 380 Lenexa, Kansas 66219 (913) 894

- 4500

In conjunction with:

E NTERGY 

### S ERVICES 

### , I NC



### . 425 West Capitol Avenue Little Rock, Arkansas 77203 (501) 377

- 40 00

Trinity Project No. 123701.0053

June 2013

### Entergy i Trinity Consultants

BART Analysis

– Lake Catherine 

## T ABLE OF 

## C ONTENTS



### 1. E XECUTIVE 

### S UMMARY



### ................................ ................................ ........................ 1

- 1

2. I NTRODUCTION AND 

### B ACKGROUND



### ................................ ................................ .... 2

- 1

3. M ODELING 

### M ETHODOLOGIES AND 

### P ROCEDURES



### ................................ ............. 3

- 1

3.1 CALMET AND 

### CALPUFF

................................ ................................ ................... 3

- 1

3.2 CALPOST

................................ ................................ ................................ ............ 3

- 1

4. E XISTING 

### E MISSIONS AND 

### V ISIBILITY 

### I MPAIRMENT



### ................................ ......... 4

- 1

4.1 NO X 

### , SO 2 

### , AND 

### PM 10 

### B ASELINE 

### E MISSION 

### R ATES



### ................................ ............... 4

- 1

4.2 B ASELINE 

### V ISIBILITY 

### I MPAIRMENT



### ................................ ................................ ....... 4

- 1

5. SO 2 

### BART E VALUATION



### ................................ ................................ .................... 5

- 1

6. NO X 

### BART E VALUATION



### ................................ ................................ ................... 6

- 1

6.1 I DENTIFICATION OF 

### A VAILABLE 

### R ETROFIT 

### NO X 

### C ONTROL 

### T ECHNOLOGIES



### ......... 6

- 1

6.2 E LIMI NATE 

### T ECHNICALLY 

### I NFEASIBLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES



### ............... 6

- 1

6.2.1 C OMBUSTION 

### C ONTROLS



### ................................ ................................ .................... 6

- 2

6.2.1.1 Burners Out of Service (BOOS)

................................ .......................... 6

- 2

6.2.1.2 Flue Gas Recirculation (FGR)

................................ ............................. 6

- 2

6.2.1.3 Separated Overfire Air (SOFA)

................................ ........................... 6

- 2

6.2.1.4 Low NO X 

### Burners

................................ ................................ ................ 6

- 2

6.2.2 P OST 

### C OMBUSTION 

### C ONTROLS



### ................................ ................................ ........... 6

- 3

6.2.2.1 Selective Catalytic Reduction (SCR)

................................ ................... 6

- 3

6.2.2.2 Selective Non

- Catalytic Reduction (SNCR)

................................ ........ 6

- 3


### 6.3 R ANK OF 

### T ECHNICALLY FEASIBLE 

### NO X 

### C ONTROL 

### O PTIONS BY 

### E FFECTIVENESS



### .. 6

- 4

6.4 E VALUATION OF 

### I MPACTS FOR 

### F EASIBLE 

### NO X 

### C ONTROLS



### ................................ ... 6

- 4

6.4.1 C OST OF 

### C OMPLIANCE



### ................................ ................................ ........................ 6

- 4

6.4.2 E NERGY 

### I MPACTS 

### & N ON



### - A IR 

### I MPACTS



### ................................ ............................ 6

- 8

6.4.3 R EMAINING 

### U SEFUL 

### L IFE



### ................................ ................................ ................... 6

- 8


### 6.5 E VALUATION OF 

### V ISIBILITY 

### I MPACT OF 

### F EASIBLE 

### NO X 

### C ONTROLS



### ..................... 6

- 8

6.6 P ROPOSED 

### B ART FOR 

### NO X



### ................................ ................................ .................. 6

- 14

7. PM 10 

### BART E VALUATION



### ................................ ................................ .................. 7

- 1

A PPENDIX 

### A (SO 2 AND 

### NO X 

### C ONTROL 

### C OST 

### C ALCULATIONS 

### )

A PPENDIX 

### B (CALMET M ODELING 

### P ROTOCOL 

### )

A PPENDIX 

### C (CEMS D ATA 

### F ROM 

### CAMD FOR 

### 2001 TO 

### 2003)

A PPENDIX 

### D (S ARGENT 

### & L UNDY 

### NO X 

### C ONTROL 

### T ECHNOLOGY 

### S TUDY 

### )

### Entergy ii Trinity Consultants

BART Analysis

– Lake Catherine 

## L IST OF 

## T ABLES

T ABLE 

### 1

- 1. E XISTING 

### V ISIBILITY 

### I MPAIRMENT 

### A TTRIBU TABLE TO 

### U NIT 

### 4

................................ ....... 1

- 1

T ABLE 

### 3

- 1. A NNUAL 

### A VERAGE 

### B ACKGROUND 

### C ONCENTRATION



### ................................ ..................... 3

- 3

T ABLE 

### 3

- 2. F L 

### (RH) L ARGE 

### RH A DJUSTMENT 

### F ACTORS



### ................................ ................................ ..... 3

- 3

T ABLE 

### 3

- 3. F S 

### (RH) S MALL 

### RH A DJUSTMENT 

### F ACTORS



### ................................ ................................ ..... 3

- 3

T ABLE 

### 3

- 4. F SS 

### (RH) S EA 

### S ALT 

### RH A DJUSTMENT 

### F ACTORS



### ................................ ............................... 3

- 3

T ABLE 

### 4

- 1. B ASELINE 

### M AXIMUM 

### 24

- HOUR 

### SO 2 

### , NO X 

### , AND 

### PM 10 

### E MISSION RATES 

### ( AS 

### H OURLY



### E QUIVALENTS 

### )

................................ ................................ ................................ ................. 4

- 1

T ABLE 

### 4

- 2. B ASELINE 

### V ISIBILITY 

### I MPAIRMENT 

### A TTRIBUTABLE TO 

### L AKE 

### C ATHERINE



### , U NIT 

### 4

B Y 

### P OLLUTANT



### ................................ ................................ ................................ ................ 4

- 2

T ABLE 

### 6

- 1. A VAILABLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES FOR 

### U NIT 

### 4

................................ ................ 6

- 1

T ABLE 

### 6

- 2. C ONTROL 

### E FFECTIVENESS OF 

### T ECHNICALLY 

### F EASIBLE 

### NO X 

### C ONTROL



### T ECHNOLOGIES



### ................................ ................................ ................................ ................ 6

- 4

T ABLE 

### 6

- 3. L AKE 

### C ATHERINE 

### U NIT 

### 4 C APACITY 

### F ACTOR S



### ................................ ................................ 6

- 5

TABLE 

### 6

- 4. S UMMARY OF 

### C OST 

### E FFECTIVENESS FOR 

### U NIT 

### 4 NO X 

### C ONTROLS



### ................................ .. 6

- 7

T ABLE 

### 6

- 5. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### BOOS FOR 

### NO X 

### C ONTROL



### .... 6

- 10

T ABLE 

### 6

- 6. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### LNB/SOFA FOR 

### NO X



### C ONTROL



### ................................ ................................ ................................ ....................... 6

- 10

T ABLE 

### 6

- 7

. S UMMA RY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### LNB/SOFA + SNCR FOR



### NO X 

### C ONTROL



### ................................ ................................ ................................ ............... 6

- 10

T ABLE 

### 6

- 8

. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### LNB/SOFA + SCR FOR



### NO X 

### C ONTROL



### ................................ ................................ ................................ ............... 6

- 10

T ABLE 

### 6

- 9. S UMMARY OF 

### V I SIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### NO X 

### C ONTROL



### S YSTEM ON 

### U NIT 

### 4 (2001

- 2003)

................................ ................................ .................... 6

- 11

T ABLE 

### 6

- 10. I NCREMENTAL 

### C OST 

### E FFECTIVENESS FOR 

### U NIT 

### 4 WITH 

### C LASS 

### I A REA



### I MPROVEMENT 

### (2001

- 2003)

................................ ................................ ......................... 6

- 13

### Entergy 1

- 1 Trinity Consultants

BART Analysis

– Lake Catherine 

## 1. E XECUT IVE 

## S UMMARY

This report is a revision to the “BART Five Factor Analysis” submitted to ADEQ on March 4 , 2013 and is being submitted to provide a comprehensive document that encompasses the determination of the Best Available Retrofit Technology (BART) for E ntergy Arkansas, Inc.’s (Entergy’s) BART

affected electric generating unit (EGU), Unit 4 at the Lake Catherine plant including revisions made in response to EPA’s comments and suggestions on the previous submittal. The BART determination for each pollutan t has not changed.

Unit 4 is a tangentially

- fired boiler with a nomina l net power rating of 558 MW and a nominal heat input capacity of 5,850 million British thermal units per hour (MMBtu/hr) that is permitted to burn natural gas and No. 6 fuel oil. E ntergy does not project to burn fuel oil at Lake Catherine Unit 4 in

the foreseeable future

, so emissions from fuel oil are not considered in this analysis. If conditions change such that it becomes economic to burn fuel oil, a five factor analysis will be submitted for approval in the State Implementation Plan (SIP) . The combustion of fuel oil would not occur until final SIP approval.

BART determination s for SO 2 

### and PM 10 

### based on the use of natural gas w ere approved in EPA’s March 12, 2012 final rule . The determinations result in no SO 2 

### or PM 10 

### controls needed during natural gas combustion.

Based on modeling performed for this analysis, combined emissions of nitrogen oxides ( NO X 

### ), sulfur dioxide (SO 2 

### ), and particulate matter with a mass mean diame ter smaller than ten microns (PM 10 

### )

from L ake Catherine Unit 4 are predicted to cause or contribute greater than 0.5 delta deciviews (∆dv) to visibility impairment in f our Class I Areas: Caney Creek Wilderness (CACR), Upper Buffalo Wilderness (UPBU), Herc ules Glades Wilderness (HERC), and Mingo Wilderness (MING) 1



### . The

contributions of the SO 2 

### and PM 10 

### emissions to the visibility impairment are negligible when compared to the contribution of NO X


### .

A summary of the existing visibility impairment attri but able to the boiler based on the default natural

conditions is provided in Table 1

- 1. T he visibility impairment summarize d in Table 1

- 1 is based on recent modeling conducted by Trinity Consultants (Trinity) using emissions data based on a combination of st ack testing

, Continuous Emission Monitoring System ( CEMS ) data as reported to EPA’s Clean Air Markets Database (CAMD)

, and AP

- 42 emission factors as further described in

Section 4 of this report.

T ABLE 

### 1

- 1. E XISTING 

### V ISIBILITY 

### I MPAIRMENT 

### A TTRIBUTABLE TO 

### U N IT 

### 4

CACR UPBU HERC MING

98th %

∆dv Days >

0.5 ∆dv 98th %

∆dv Days >

0.5 ∆dv 98th %

∆dv Days >
0.5 ∆dv 98th %

∆dv Days >

0.5 ∆dv

1.371 80 0.532 21 0.387 8 0.429 7

1 Sipsey Wilderness was included in the Arkansas D epartment of E nvironmental Q uality '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

– Lake Catherine Trinity used the EPA’s BART guidelines in 40 CFR Part 51 2 

### to determine BART for Unit 4

. Specifically, Trinity cond ucted a five

- step analysis to determine BART for NO X 

### that included the following:

1. 

### Identif

ying all available retrofit control technologies;

2. 

### Eliminat ing technically infeasible control technologies;

3. 

### Evaluat ing the control effectiveness of remaining control t echnologies;

4. 

### Evaluating impacts and document the results ;
5. 

### Evaluating visibility impacts

.

The BART analysis concludes that for NO X 

### , the achievement of an emission rate of 0.24 lb/MMBtu through the installation and use of Burners Out of Service (BOOS) repre sents BART. 3

2 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.

3 EPA recently issued a final rule allowing states that are subject to the Cross

- State Air Pollution Rule (CSAPR) trading program for seasonal NO X 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 ultimatel y is upheld and implemented in Arkansas, Entergy may rely on CSAPR to satisfy its NO X regional haze obligations at Unit 4

. Alternatively, if CSAPR is vacated and CAIR remains in place, Entergy may rely on CAIR to satisfy its NO X obligations under BART a s EPA has previously

determined that the CAIR season NO X trading program provides greater visibility improvement than BART.

### Entergy 2

- 1 Trinity Consultants

BART Analysis

– Lake Catherine 

## 2. I NTRODUCTION AND 

## B ACKGROUND

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 require s 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 Techno logy (BART) rule, which included guidance for making source

- specific BART determinations. 4 

### 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

- im pairing 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

cont ribute 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 98 th 

### percentile visibility impacts from the source are modeled to be greater than 0.5 delta decivie ws (∆dv) when compared against a natural background. 5 

### 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 cont

rol 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 em itted 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 pol lution 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.

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

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

. 5 The original modeling for Ar kansas sources relied on screening met data and, as such, reviewed the maximum impact rather than the 98 th percentile impact. Use of the 98 th percentile impact based on the use of refined met data (such as that used in the modeling conducted as part of th is 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

– Lake Catherine 1. 

### Existing controls

2. 

### Cost of controls

3. 

### Energy and non

- air quality environmental impacts

4. 

### Remaining useful life of the source

5. 

### Degree of visibility improvement as a result of c ontrols

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 effectiv eness of remaining control technologies;

4. 

### Evaluate impacts and document the results;

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.

Unit 4 meets the three BART

- eligibility criteria described above, and the existing visibility impairment attributable to the boiler is greater than 0.5 ∆dv in at least one Class I area. Thus, Unit 4 is subject to BART. Details of the existing/baseline emissi ons and the contribution of the emissions to visibility impairment can be found in Section 4. The VAPs emitted by the boiler include NO X 

### , SO 2 

### , and PM 10 

### of various forms (filterable coarse particulate matter [PM

c 

### ], filterable fine particulate matter [PM f



### ], elemental carbon [EC], inorganic condensable particulate matter [IOR CPM] as sulfates [SO 4 

### ], and organic condensable particulate matter [OR CPM] also referred to as secondary organic aerosols [SOA]).

### Entergy 3

- 1 Trinity Consultants

B ART Analysis

– Lake Catherine 

## 3. M ODELING 

## M ETHODOLOGIES AND 

## P ROCEDURES

This secti on 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 proc essor, 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 o ther 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

informati on 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 CALM ET 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 sum marizes 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 deve loped 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) 6



### .

Visibility impairment is quantified using the light extinction coefficient ( b ext 

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

The impac t 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

6 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.

### Entergy 3

- 2 Trinity Consultants

B ART Analysis

– Lake Catherine as “delta dv,” or ∆dv, based on the source and background light extinction is based on the following equation:

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 

### :

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:

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

salt

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

and nitrates and for sea salts

 Rayleigh scattering parameter corrected for site

- specific elevation

Tables 3

- 1 to Table 3

- 4 below show the va lues 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.

### Entergy 3

- 3 Trinity Consultants

B ART Analysis

– Lake Catherine

T ABLE 

### 3

- 1. A NNUAL 

### A VERAGE 

### B ACKGROUND 

### C ONCENTRATION

Class I Area (NH 4 ) 2 SO 4

(μg/m 3 ) NH 4 NO 3

(μg/m 3 ) OM

(μg/m 3 ) EC

(μg/m 3 ) Soil

(μg/m 3 ) CM

(μg/m 3 ) Sea Salt

(μg/m 3 ) 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



### T ABLE 

### 3

- 2

. F L 

### (RH) L ARGE 

### RH A DJUSTMENT 

### F ACTORS

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



### T ABLE 

### 3

- 3

. F S 

### (RH) S MALL 

### RH A DJUSTMENT 

### F ACTORS

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



### T ABLE 

### 3

- 4

. F SS 

### (RH) S EA 

### S ALT 

### RH A DJUSTMENT 

### F ACTORS

Cl ass 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

### Entergy 4

- 1 Trinity Consultants

BART Analysis

– Lake Catherine



## 4. E XISTING 

## E MISSIONS AND 

## V ISIBILITY 

## I MPAIRMENT

This section summarizes the existing (i.e.

, baseline) visibility impairment attributable to Unit 4 based on air quality modeling conducted by Trin ity.



## 4.1 NO X 

## , SO 2 

## , AND 

## PM 10 

## B ASELINE 

## E MISSION 

## R ATES

Table 4

- 1 summarizes the emission rates that were modeled for SO 2 

### , NO X 

### , and PM 10 

### , including the speciated PM 10 

### emissions. The SO 2 

### and NO X 

### emission rates are the highest actual 24

- hour emission

rates based on 200 1

- 200 3 continuous emissions monitoring system (CEMS)

. 7 

### Please note that CEMS data from these years is representative of burning only natural gas.

The emission rates for the PM 10 

### species reflect the breakdown of the filterable and condensable PM 10 

### d etermined from AP

- 42 Table 1.4

- 2 Combustion of Natural Gas

. A ll filterable PM was assumed to

be elemental carbon , as this is the assumption that the National Park Service (NPS) uses for filterable

PM 10 

### from natural gas fired combustion turbines , and the N PS does not have a speciation analysis specific to gas fired boilers

. All of the condensable PM was assumed to be SOA, except for a small

fraction of the condensable PM that was estimated to be SO 4



### . One

- third of the estimated SO 2 

### emissions were separated and adjusted for differences in molecular weight to represent SO 4 

### emissions. This essentially double counts some of the fuel sulfur based emissions as SO 2 

### but also as

SO 4 

### . Since pipeline natural gas contains very little sulfur, both the SO 2 

### and SO 4 

### emis sion rates are very low.

T ABLE 

### 4

- 1

. B ASELINE 

### M AXIMUM 

### 24

- HOUR 

### SO 2 

### , NO X 

### , AND 

### PM 10 

### E MISSION RATES 

### ( AS 

### H OURLY


### E QUIVALENTS 

### )

Unit SO 2 8 NO X 9 Total

PM 10 SO 4 PM

c PM f SOA EC (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr)

Unit 4 3.1 2,456.4 44.3 1.5 0.0 0.0 31.8 11.0



## 4.2 B ASELINE 

## V ISIBILITY 

## I MPAIRMENT

Trinity conducted modeling to determine the visibility impairment attributable to Unit 4 in four Class I Areas: Caney Creek Wilderness (CACR), Upper Buffalo Wilderness (UPBU), Hercules Glades

Wilderne ss (HERC), and Mingo Wilderness (MING) using the CALPUFF dispersion model. Table

4

- 2 provide s a summary of the modeled visibility im pairment attributable to Unit 4 at CACR, UPBU,
HERC, and MING based on the emission rates shown in Table 4

- 1

. Table 4

- 2 th e maximum

7 See Appendix C

8 The SO 2 hourly rate was derived from EPA’s CAMD . The 2001

- 2003 max daily rate was 74 lb/day

. See

Appendix C

.

9 The NO

x hourly rat e was derived from EPA’s CAMD . The 2001

- 2003 max daily rate was 58,954 lb/day

. See

Appendix C

.

### Entergy 4

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BART Analysis

– Lake Catherine impairment in Δdv, the 98 th 

### percentile impacts in Δdv, and the number of days with impacts greater than 0.5 Δdv as well as the breakdown by pollutant species for the 98 th 

### percentile impact.

As BART is determined on a unit

- by

- unit basis, this b aseline 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 s ubmitted with this document.

T ABLE 

### 4

- 2

. B ASELINE 

### V ISIBILITY 

### I MP AIRMENT 

### A TTRIBUTABLE TO 

### L AKE 

### C ATHERINE 

### , U NIT 

### 4

B Y 

### P OLLUTANT

Year Maximum

(Δdv) 98th

Percentile (Δdv) No. of Day

with Δdv ≥

0.5 98th

Percentile
% SO 4 98th

Percentile
% NO 3 98th

Percentile

% PM 10 98th

Percentile
% NO 2 Caney Creek Wilderness

2001 3.480 1.371 31 0.49 85.13 0.00 8.55

2002 3.318 0.909 21 0.31 92.53 0.00 4.18

2003 3.276 1.233 28 0.43 85.66 0.00 7.76
Upper Buffalo Wilderness

2001 1.478 0.489 7 0.33 89.54 0.00 5.99

2002 0.916 0.532 9 0.22 96.29 0.00 1.26

2003 2.044 0.412 5 0.21 97.36 0.00 0.30

Hercules Glades Wilderness

2001 0.760 0.387 4 0.30 91.12 0.00 4.92

2002 1.016 0.313 2 0.39 88.73 0.00 6.08

2003 0.881 0.311 2 0.38 93.27 0.00 2.57
Mingo Wilderness

2001 0.511 0.237 1 0.30 92.55 0.00 3.17

2002 0.763 0.429 5 0.32 96.25 0.00 0.44

2003 0.516 0.214 1 0.18 98.08 0.00 0.10

### Entergy 5

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BART Analysis

– Lake Catherine 

## 5. SO 2 

## BART E VALUATION

A BART deter mination for SO 2 

### based on the use of natural gas w as approved in EPA’s March 12,

2012

, final rule . The determination results in no SO 2 

### controls needed during natural gas

combustion

. 10

10 “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 6

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BART Analysis

– Lake Catherine 

## 6. N O X 

## BART E VALUATION



## 6.1 I DENTIFICATION OF 

## A VAILABLE 

## R ETROFIT 

## NO X 

## C ONTROL



## T ECHNOLOGIES

Nitrogen oxides, NO X 

### , 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 lead to the use of the t erms “thermal” NO X 

### and “fuel” NO X 

### when describing NO X 

### emissions . Thermal NO X 

### emissions are produced when elemental nitrogen in the combustion air is exposed to a high temperature zone and oxidized. Fuel NO X 

### emissions are created during the rapid

oxidation of nitrogen compounds contained in the fuel.

Nitrogen oxide (NO) is typically the predominant form of NO X 

### from fossil fuel combustion. Nitrogen dioxide (NO 2 

### ) makes up the remainder of the NO X 

### . The formation of NO X 

### compounds in utility

boilers is sensi tive to the method of firing. In tangentially

- fired boilers, such as Unit 4 , 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 typica lly have lower uncontrolled NO X 

### emissions than wall

- fired boilers. Therefore baseline NO X 

### 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 identifi cation of all available retrofit NO X 

### control technologies. The available retrofit NO X 

### control technologies are summarized in Table 6

- 1.

NO X 

### emissions controls, as listed in Table 6

- 1 , can be categorized as combustion or post

- combustion

controls. Combust ion controls, including Burners Out of Service (BOOS), flue gas recirculation (FGR ), overfire air / separated overfire air ( SOFA ), and Low NO

x 

### Burners (LNB), reduce the peak flame temperature and excess air in the furnace which minimizes NO X 

### formation. Po st

- combustion controls, such as selective catalytic reduction (SCR) and selective non

- catalytic reduction (SNCR)

, convert NO X 

### in the flue gas to molecular nitrogen and water.

T ABLE 

### 6

- 1

. A VAILABLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES FOR 

### U NIT 

### 4

NO X Control Technolog ies

Combustion Controls Burners Out of Service (BOOS)

Flue Gas Recirculation (FGR)

Separated Overfire Air ( SOFA )

Low 

### NO

x Burners (LNB)

Post

- Combustion Controls Selective Catalytic Reduction (SCR)

Selective Non

- Catalytic Reduction (SNCR)



## 6.2 E LIMIN ATE 

## T ECHNICALLY 

## I NFEASIBLE 

## NO X 

## C ONTROL 

## T ECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible NO X 

### control technologies that were identified in Step 1.

### Entergy 6

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BART Analysis

– Lake Catherine 

### 6.2.1 C OMBUSTION 

### C ONTROLS



### 6.2.1.1 B URNERS 

### O UT OF 

### S ERVICE 

### (BOOS)

BOOS is a staged combus tion technique whereby fuel is introduced though operational burners in the lower furnace zone to create fuel

- rich conditions, while not introducing fuel to other burners. Additional air is then supplied to

the non

- operational burners to complete combusti on. By removing fuel from certain zones, the temperature is reduced, and the production of thermal NO X 

### is

also reduced. When operated without additional controls, the estimated

controlled NO X 

### level for Unit 4 operating with BOOS is 0.24 lb/MMBtu

. 11



### This co ntrol is a technically feasible option for the control of NO X 

### from Unit 4

.



### 6.2.1.2 F LUE 

### G AS 

### R ECIRCULATION 

### (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 combust ion

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; w hich in turn reduces thermal NO X 

### formation

. When operated without additional controls, the estimated controlled NO X 

### level for Unit 4 operating with FGR is 0.19 lb/MMBtu

. 12 

### This control is a technically feasible option for the control of NO X 

### from Unit 4

.



### 6.2.1.3 S EPARATED 

### O VERFIRE 

### A IR 

### ( SOFA )

SOFA 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 l ower peak flame temperature. This reduces the formation of thermal NO X 

### by lowering combustion temperature and limiting the availability of oxygen in the

combustion zone where NO X 

### is most likely to be formed. When operated

without additional controls

, SOF A results in estimated NO X 

### emissions for gas fired boilers of 0.2

- 0. 4 lb/MMBtu. 13 

### This control is a technically feasible option for the control of NO X 

### from Unit 4

.



### 6.2.1.4 L OW 

### NO X 

### B URNERS



### LNB technology utilizes advanced burner design to reduce NO X 

### formation

throu gh the restriction of oxygen, lowering of flame temperature, and/or

reduced residence time. NO X 

### creation rates typically peak at oxygen levels of five to seven percent. 14 

### LNB is a staged combustion process that is designed to split fuel combustion into tw o zones. In the primary zone, NO X 

### formation is

11 Sargent & Lundy May 16, 2013 NOx Control Technology Cost and Performance Study (S&L 2013 Study).

12 Id.

13 “Controlling Nitrogen Oxides Under the C lean Air Act: A Menu of Options.” Utility Boiler section. July

1994.

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

### Entergy 6

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BART Analysis

– Lake Catherine

limited by one of two methods. Under staged fuel

- rich condition s , low oxygen levels limit flame temperatures resulting in less NO X 

### formation. The primary zone is then followed by a secondary zone in which t he 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 NO X 

### formation. In the secondary zone, combustion products formed in the primary zone act to lower the local oxygen concentration, resulting in a

decrease in NO X 

### formation.

When operated without additional controls , LNB results in estimated NO X 

### emissions for gas fired boilers of approximately 0. 25 lb/MMBtu. 15 

### When

combine d with SOFA , t he estimated NO X 

### control level is 0. 19 lb/MMBtu. 16



### LNB systems are technically feasible for the control of NO X 

### from Unit 4

.



### 6.2.2 P OST 

### C OMBUSTION 

### C ONTROLS



### 6.2.2.1 S ELECTIVE 

### C ATALYTIC 

### R EDUCTION 

### (SCR)

SCR refers to the process in which NO X 

### is reduced by ammon ia over a heterogeneous catalyst in the presence of oxygen. The process is termed selective because the ammonia preferentially reacts with NO X 

### rather than oxygen, although the oxygen enhances the reaction and is a necessary component of the process. The overall reactions are:

4NO + 4NH 3 + O 2  4N 2 + 6H 2 O

2NO 2 + 4NH 3 + O 2  3N 2 + 6H 2 O



### 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 fac tors, including the inlet NO X 

### concentration, the exhaust temperature, the ammonia injection rate, and the type of catalyst. When combined with SOFA

and LNB , t he estimated NO X 

### control level is 0. 03 lb/MMBtu. 17 

### This control is a technically feasible option f or the control of NO X 

### from Unit 4

.



### 6.2.2.2 S ELECTIVE 

### N ON



### - C ATALYTIC 

### R EDUCTION 

### (SNCR)

In SNCR systems, a reagent is injected into the flue gas in the furnace within an appropriate temperature window. The NO X 

### and reagent (ammonia or urea) 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 or four times as much reagent as SCR systems to achieve similar

NO X 

### reductions. When combined with SOFA and LNB , t he estimated NO X

15 “Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options.” Utility Boiler section. July 1994.

16 S&L 2013 Study.

17 Id.

### Entergy 6

- 4 Trinity Consultants

BART Analysis

– Lake Catherine

control level is 0. 14 lb/MMBtu. 18 

### This control is being evaluated as a technically feasible opt ion for the control of NO X 

### from Unit 4; however this technology is not adaptable to all gas

- fired boilers

.



## 6.3 R ANK OF 

## T ECHNICALLY FEASIBLE 

## NO X 

## C ONTROL 

## O PTIONS BY 

## E FFECTIVENESS

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

effectiveness. Table 6

- 2 provides a ranking of the control levels for the controls listed in the previous section for Unit 4

.

T ABLE 

### 6

- 2

. C ONTROL 

### E FFECTIVENESS OF 

### T ECHNICALLY 

### F EASIBLE 

### NO X 

### C ONTROL


### T ECHNOLOGIES

Control Technology Estimated Contro lled

Level for Unit 4 (lb/MMBtu)

SOFA 0. 30

LNB 0. 25

BOOS 0.24

LNB/ SOFA OR FGR 0.19

LNB/SOFA + SNCR 0.14

LNB/SOFA + SCR 0.0 3



## 6.4 E VALUATION OF 

## I MPACTS FOR 

## F EASIBLE 

## NO X 

## C ONTROLS

Step four for the BART analysis is the impact a nalysis. The BART determination guidelines list four factors to be considered in the impact analysis:

▲ 

### Cost of compliance

▲ 

### Energy impacts

▲ 

### Non

- air quality impacts; and

▲ 

### The remaining useful life of the source



### 6.4.1 C OST OF 

### C OMPLIANCE



### The capital costs, operating c osts, and cost effectiveness of BOOS, LNB/ SOFA

, LNB/ SOFA / SNCR and LNB/ SOFA / SCR were estimated for the cost analysis. Since FGR

results in the same controlled emission level as LNB/ S OFA but at a higher cost 19 

### , FGR is not considered further in the analysis.

18 S&L 2013 Study

. 19 Id.

### Entergy 6

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BART Analysis

– Lake Catherine

Control Costs Control costs were calculated using cost estimates developed by Sargent and Lundy

. T he capital costs were annualized over a 15

- year period and then added to the annual operating

costs to obtain the total annualized costs.

The capital an d operating cost estimates are provided in Appendix A of this report.

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 calculated using the baseline emission level of 0.48 lb/MMBtu and an annual heat input reflecting a ten percent capacity factor

. 20



### EPA states in the BART g uidelines that “The baseline emission rate should represent a realistic depiction of anticipated annual emissions for the source.” While the average annual capacity factor for Unit 4 from 2001

- 2003 , which are the b a seline years from which the peak daily NO X 

### emission rate was determin ed as described in Section 4 of this r e port, was approximately 20 percent

, Entergy anticipate s that future utilization of Unit 4 will remain in the range of 10 percent

, which is consistent with the recent operating history of

the unit.

Table 6

- 3 below ill ustrates the annual capacity factor values for Unit 4 over the past ten years (2003

- 2012). Typical utilization of this unit has been less than 5 percent on an annual basis. Utilization in 2012 was slightly higher than 10 percent due to anomalous grid rel iability issues which resulted in a need for greater utilization. These issues are not expected to arise in future years and future annual capacity factors are expected to be comparable to those experienced by the unit in 2003

- 2011. EPA has stated that t hey agree that the unit has historically operated at less than a 10 percent capacity factor and that a source may calculate baseline emissions based on a continuation of past practice

. 21 

### A 10

percent capacity factor has been used for this analysis as a con servative estimate.

T ABLE 

### 6

- 3. L AKE 

### C ATHERINE 

### U NIT 

### 4 C APACITY 

### F ACTOR S



### 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

10.4 3.2 4.2 0.5 0.7 2.7 3.0 3.1 2. 3 12.8

The controlled annual emission rate s were based on lb/MMBtu levels believed to be

achievabl e from the control technolog ies multiplied by the annual heat input

. The annual heat input used to calculate the annual controlled emission rates was the same heat input

that was used to calculate baseline annual emissions

.

20 The annual heat input reflect ing a 10% annual capacity factor is 5,124,600 MMBtu/yr (5,850 MMBtu/hr * 8760 hrs/yr * 10% = 5,124,600 MMBtu/yr)

. 21 77 F ed. R eg. 14641

.

### Entergy 6

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BART Analysis

– Lake Catherine

Cost Effectiveness

The cost ef

fectiveness in dollars per ton of NO X 

### reduced was determined by dividing the annualized cost of control by the annual tons reduced. An incremental cost analyses was also performed to show the incremental increase in the cost of controls when compared to

B OOS . The costs effectiveness analysis is summarized in Table 6

- 4

.

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 post

combustion contr ols. EPA estimates that approximately 75 percent of the BART units
(non

- cyclone) could mee t the presumptive NO X 

### limits at a cost of $100 to $1,000 per ton of

NO X 

### removed based on the use of combustion control technology. 22 

### For the units that

could not mee t 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 $1,5 00 per ton of NO X 

### removed. 23



### Table 6

- 4 indicates that the cos t effectiveness of BOOS is approximately $ 150 per ton of

NO X 

### removed. Further, the incremental cost effectiveness of LNB/ SOFA over BOOS is approximately $ 9, 0 00/ton

, while the incremental cost of LNB/ SOFA / SNCR ove r
LNB/SOFA is approximately $ 17 ,000/ton and the incremental cost LNB/ SOFA / SCR over
LNB/SOFA is approximately $ 14 ,000/ton

.

Table 6

- 4 also summarizes the improvement in the maximum of the 98 th 

### percentile visibility impairment results d ue to each control technology. Details of the post

- control modeling results are provided later in Section 6.5, but this summary is presented here for

convenience. As Table 6

- 4 clearly shows, BOOS results in over 0.5 Δ dv of visibility improvement when compared the baseline visibility impairment. While LNB/ SOFA

, LNB/ SOFA / SNCR , and LNB/ SOFA /SCR offer some additional visibility improvement

over BOOS , up to a maximum of 0.672 Δ dv of additional improvement for

LNB/ SOFA /SCR , the very high incremental costs when compared to BOOS can not be justified

.

22 “Regional Haze Regulatio ns and Guidelines for Best Available Retrofit Technology (BART Determinations; Final Rule.) 77 F ed. R eg. 39134

- 39135 (July 6, 2005)

.

23 Id.

### Entergy 6

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BART Anal ysis

– Lake Catherine TABLE 

### 6

- 4

. S UMMARY OF 

### C OST 

### E FFECTIVENESS FOR 

### U NIT 

### 4 NO X 

### C ONTROLS

### Entergy 6

- 8 Trinity Consultants

BART Analysis

– Lake Catherine 

### 6.4.2 E NERGY 

### I MPACTS 

### & N ON



### - A IR 

### I MPACTS



### As noted in Table 6

- 4 , SCR and SNCR systems are capable of ac hieving additional NO X 

### reductions when compared to combustion controls such as BOOS, LNB, or 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

effecti ve reaction with NO X 

### , leading to an excess of unreacted ammonia, or from over

injection 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 NO X 

### - 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. Idea lly 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 cataly sts 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 a dditional potential financial and environmental impa cts associated with an SCR system.



### 6.4.3 R EMAINING 

### U SEFUL 

### L IFE



### The remaining useful life of Unit 4 is sufficiently long such that it does not affect the BART analysis

.



## 6.5 E VALUATION OF 

## V ISIBILITY 

## I MPACT OF 

## F EASIBLE 

## NO X 

## C ONTROLS

A final impact analysis was conducte d to assess the visibility improvement for existing emission rates when compared to the emission rates associated with BOOS, LNB/ SOFA , LNB/ SOFA / SNCR

, and

### Entergy 6

- 9 Trinity Consultants

BART Analysis

– Lake Catherine LNB/ SOFA / SCR . Section 4 of this report documented the existing visibility impairment attributable

to Unit 4

. In order to assess the visibility improvement associated with BOOS, LNB / SOFA , SCR and SNCR systems, the NO X 

### emission rates associated with the control systems were modeled using

CALPUFF. The controlled emission level associated with BOOS is 0.24 lb/MMBtu; t he controlled

emission level associated with an LNB/ SOFA system is 0. 19 lb/MMBtu ; t he controlled emission

level associated with an L NB/ SOFA /SNCR system is 0. 14 lb/MMBtu, and the controlled emission

level associated with an LNB/ SOFA /SCR system is 0. 03 lb/MMBtu. These levels were multiplied by the maximum heat input (5,850 MMBtu/hr) to derive hourly the hourly emission rates used in the modeling

.

Tables 6

- 5 through 6

- 8 summarize the NO X 

### emission rates that were modeled to reflect the BOOS,

LNB/ SOFA

, LNB/ SOFA /SNCR and LNB/ SOFA / SCR control options . The emission rates for the other pollutants shown in Tables 6

- 5 through 6

- 8 are the same as in the baseline modeling.

### Entergy 6

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BART Analysis

– Lake Catherine T ABLE 

### 6

- 5

. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### BOOS FOR 

### NO X 

### C ONTROL

S O 2 (lb/hr) SO 4

(lb/hr) 

### NO X

(lb/hr) PM C

(lb/hr) PM F

(lb/hr) SOA

(lb/hr) EC

(lb/hr) PM 10, total

(lb/hr)

Unit 4 3.1 1.5 1,404.0 0.0 0.0 31.8 11.0 44.3



### T ABLE 

### 6

- 6

. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### LNB/ SOFA FOR 

### NO X 

### C ONTROL

SO 2 (lb/hr) SO 4

(lb/hr) 

### NO X

(lb/hr) PM C

(lb/hr) PM F

(lb/hr) SOA

(lb/hr) EC

(lb/hr) PM 10, total

(lb/hr)

Unit 4 3.1 1.5 1,111.5 0.0 0.0 31.8 11.0 44.3



### T ABLE 

### 6

- 7

. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### LNB/SOFA + SNCR FOR 

### NO X 

### C ONTROL

SO 2 (lb/hr) SO 4

(lb/hr) 

### NO X

(lb/hr) PM C

(lb/hr) PM F

(lb/hr) SOA

(lb/hr) EC

(lb/hr) PM 10, total

(lb/hr)

Unit 4 3.1 1.5 819.0 0.0 0.0 31.8 11.0 44.3



### T ABLE 

### 6

- 8

. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### LNB/ SOFA + SCR FOR 

### NO X 

### C ONTROL

SO 2 (lb/hr) SO 4

(lb/hr) 

### NO X

(lb/hr) PM C

(lb/hr) PM F

(lb /hr) SOA

(lb/hr) EC

(lb/hr) PM 10, total

(lb/hr)

Unit 4 3.1 1.5 1 75.5 0.0 0.0 31.8 11.0 44.3



### Table 6

- 9 provides a comparison of the existing visibility impairment and the visibility impairment

associated with the addition of NO X 

### controls on Unit 4 in all affected Class I areas , including the maximum modeled visibility impact, 98 th 

### p ercentile modeled visibility impact, and the number of days with a modeled visibility impact greater than 0.5 Δdv.

### Entergy 6

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BART Analysis

– Lake Catherine

T ABLE 

### 6

- 9

. S UMMARY OF 

### V ISIBILITY 

### I MPROVEMENT 

### A SSOCIATED WITH 

### NO X 

### C ONTROL 

### S YSTEM ON 

### U NIT 

### 4 (2001

- 2003)

Caney Creek Wilderness Upper Buffa lo Wilderness Hercules Glades Wilderness Mingo NWR Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv

Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv

Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv

Existing Emission Rate 3.480 1.371 80 2.044 0.532 21 1.016 0.387 8 0.763 0.429 7

BOOS 2.154 0.835 37 1.232 0.307 11 0.6 0.229 2 0.447 0.253 0

Post Control

Improvement 1.326 0.536 43 0.812 0.225 10 0.416 0.158 6 0.316 0.176 7

LNB/ SOFA 1 .759 0.683 28 0.996 0.25 9 0.482 0.185 0 0.358 0.204 0

Incremental Post
Control Improvemen t

over BOOS 0.395 0.152 9 0.236 0.057 2 0.118 0.044 2 0.089 0.049 0

LNB/SOFA/ S N CR 1.349 0.529 16 0.755 0.193 4 0.362 0.141 0 0.268 0.154 0

Incremental Post

Control Improvemen t

over BOOS 0.805 0.306 21 0.477 0.114 7 0.238 0.088 2 0.179 0.099 0

LNB/SOFA/ SCR 0.452 0.163 0 0.211 0.057 0 0.101 0.043 0 0.082 0.042 0

Incremental Post
Control Improvement

over BOOS 1.702 0.672 37 1.021 0.25 11 0.499 0.186 2 0.365 0.211 0

†The visibility improvement shown in the table has been calculated from 98 th percentile baseline and controlled impacts that include more decimal places than what is
shown in the table. Due to rounding of the baseline and controlled 98 th percentile impact s shown in the table, the visibility improvement calculated from the baseline and

controlled 98 th percentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.

### Entergy 6

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BART Analysis

– Lake Catherine As shown in Table 6

- 9 , based on visibi lity predictions from the CALPUFF modeling system, the operation of a BOOS will result in up to a 0. 536 Δ dv improvement (depending on the Class I area) to the existing visibility impairment attributable to Unit 4 . This visibility improvement increases by

0. 152 Δdv for LNB/ SOFA (0. 835

- 0. 683 = 0.152)

, 0.306 Δdv for LNB/ SOFA / S NCR (0. 8 35

- 0. 5 29 = 0.306) , and 0.672 Δdv for LNB/ SOFA / S CR ( .835

- 0. 163 = 0.672)

.

For convenience, Table 6

- 10 provide s a condensed summary of these predicted improvements alongside the es timated control costs. The increme ntal visibility benefit of going from BOOS to
either LNB/ SOFA , LNB/ SOFA / SCNR or LNB/ SOFA / SCR is clearly not justified by the high

incremental cost difference . The control technolog ies are very expensive from an initial c apital

investment and prohibitively more expensive from an increment al cost effectiveness standpoint than

BOOS

.

### Entergy 6

- 13 Trinity Consultants

BART Analysis

– Lake Catherine

T ABLE 

### 6

- 10

. I NCREMENTAL 

### C OST 

### E FFECTIVENESS FOR 

### U NIT 

### 4 WITH 

### C LASS 

### I A REA 

### I MPROVEMENT 

### (2001

- 2003)

### Entergy 6

- 14 Trinity Consultants

BART Analysis

– Lake Catherine



## 6.6 P ROPOSED 

## B ART FOR 

## NO X



### Entergy propo ses a BART emission rate of 0. 24 lb/MMBtu on a 30

- day rolling average basis, achievable through use of BOOS at Unit 4. 24

24 If CSAPR is upheld and implemented in Arkansas, Entergy will rely on CSAPR to satisfy its regional haze obligation s at Lake Catherine. If CSAPR is vacated and CAIR remains in effect, EPA’s prior determination that the reductions provided under CAIR’s seasonal NO X trading program provide greater visibility improvements than BART

should allow Entergy to rely on the sea sonal CAIR program to satisfy its NO X obligations under BART

.

### Entergy 7

- 1 Trinity Consultants

BART Analysis

– Lake Catheri ne 

## 7. PM 10 

## BART E VALUATION

A BART determination for PM 10 

### based on the use of natural gas w as approved in EPA’s March 12,

2012

, final rule

. The determination results in no PM 10 

### controls needed during natural gas

combustion

. 25

25 “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 Trinity Consultants

BART Analysis

– Lake Catherine 

## A PPENDIX 

## A

C ONTROL 

### C OST 

### C ALCUL A TIONS

### Entergy Trinity Consultants

BART Analysis

– Lake Catherine

### Entergy Trinity Consultants

BART Analysis

– Lake Catherine

### Entergy Trinity Consultants

BART Analysis

– Lake Catherine

### Entergy Trinity Consultants

BART Analysis

– Lake Catherine

### Entergy Trinity Consultants

BART Analysis

– Lake Catherine 

## A PPENDIX 

## B

M ODELING 

### P ROTOCOL



### As stated in Section 3.1, the meteorological data u sed 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.

### Entergy Trinity Consultants

BART Analysis

– Lake Catherine 

## A PPENDIX 

## C

CEMS D ATA 

### F ROM 

### CAMD FOR 

### 2001 T O 

### 2003

# CALMET D ATA 

# P ROCESSING 

# P ROTOCOL  

# BART D ETERMINATION 

# O KLAHOMA 

# G AS 

# & E LECTRIC

M USKOGEE 

### G ENERATING 

### S TATION 

### S EMINOLE 

### G ENERATING 

### S TATION 

### S OONER 

### G ENERATING 

### S TATION



### Prepared by:

Vern Choquette  

### Principal Consultant Eugene Chen, PE  

### Senior Consultant

Jerem y Townley  

### Consultant

T RINITY 

### C ONSULTANTS 

### 120 East Sheridan

Suite 205 Oklahoma City, OK 73104

(405) 228

- 3292

January 2 3 , 2008

Project 0 83701 .00 04

### OG&E i Trinity Consultants

CALMET Processing Protocol 083701.0004 

## T ABLE OF 

## C ONTENTS



### 1. I NTRODUCTION



### ................................ ................................ ................................ .... 1

- 1

1.1 B EST 

### A VAILABLE 

### R ETROFIT 

### T ECHNOLOGY 

### R ULE 

### B ACKGROUND



### ......................... 1

- 1

1.2 O BJECTIVE



### ................................ ................................ ................................ ............ 1

- 2

1.3 L OCATION OF 

### S OURCES AND 

### R ELEVANT 

### C LASS 

### I A REAS



### ................................ ...... 1

- 2

2. CALPUFF M ODEL 

### S YSTEM



### ................................ ................................ ............... 2

- 1

2.1 M ODEL 

### V ERSIONS



### ................................ ................................ ................................ . 2

- 1

2.2 M ODELING 

### D OMAIN



### ................................ ................................ ............................. 2

- 1

3. CALMET

................................ ................................ ................................ ............ 3

- 1

3.1 G EOPHYSICAL 

### D ATA



### ................................ ................................ ............................. 3

- 1

3.1.1 T ERRAIN 

### D ATA



### ................................ ................................ ................................ ... 3

- 1

3.1.2 L AND 

### U SE 

### D ATA



### ................................ ................................ ................................ . 3

- 2

3.1.3 C OMPILING 

### T ERRAIN AND LAND 

### U SE 

### D ATA



### ................................ ....................... 3

- 3


### 3.2 M ETEOROLOGICAL 

### D ATA



### ................................ ................................ ..................... 3

- 3

3.2.1 M ESOSCALE 

### M ODEL 

### M ETEOROLOGICAL 

### D ATA



### ................................ ................. 3

- 3

3.2.2 S URFACE 

### M ETEOROLOGICAL 

### D ATA



### ................................ ................................ ... 3

- 4

3.2.3 U PPER 

### A IR 

### M ETEOROLOGICAL 

### D ATA



### ................................ ................................ . 3

- 5

3.2.4 P RECIPITATION 

### M ETEOROLOGICAL 

### D ATA



### ................................ .......................... 3

- 6

3.2. 5 B UOY 

### M ETEOROLOGICAL 

### D ATA



### ................................ ................................ ......... 3

- 7


### 3.3 CALMET C ONTROL 

### P ARAMETERS



### ................................ ................................ ....... 3

- 8

3.3.1 V ERTICAL 

### M ETEOROLOGICAL 

### P ROFILE



### ................................ .............................. 3

- 8

3.3.2 I NFLUENCES OF 

### O BSERVATIONS



### ................................ ................................ ......... 3

- 9



### A PPENDIX 

### A

- M ETEOROLOGICAL 

### S TATIONS



### A PPENDIX 

### B

– S AMPLE 

### CALMET C ONTROL 

### F ILE 

### (CALPUFF V ERSION 

### 5.8)

A PPENDIX 

### C

– S AMPLE 

### CALMET C ONTROL 

### F ILE 

### (CALPUFF V ERSION 

### 6)

### OG&E ii Trinity Consultants

CALMET Processing Protocol 083701.0004 

## L IST OF 

## T ABLES

T ABLE 

### 1

- 1. BART

- E LIGIBLE 

### S OURCES



### ................................ ................................ ............................... 1

- 2

T ABLE 

### 1

- 2. D ISTANCE 

### F ROM 

### S TATION TO 

### S URROUNDING 

### C LASS 

### I A REAS



### ................................ ....... 1

- 2

T ABLE 

### 2

- 1. CALPUFF M ODELING 

### S YSTEM 

### V ERSIONS



### ................................ ................................ ..... 2

- 1

T ABLE 

### 3

- 1. V ERTICAL 

### L AYERS OF THE 

### CALMET M ETEOROLOGICAL 

### D O MAIN



### ................................ 3

- 9

T ABLE 

### A

- 1. L IST OF 

### S URFACE METEOROLOGICA L 

### S TATIONS



### ................................ ........................... A

- 1

T ABLE 

### A

- 2. L IST OF 

### U PPER 

### A IR METEOROLOGICAL 

### S TATIONS



### ................................ ......................... A

- 5

T ABLE 

### A

- 3. L IST OF 

### P RECIPITATION METEORO LO GICAL 

### S TATIONS



### ................................ .................. A

- 6

T ABLE 

### A

- 4. L IST OF 

### O VER 

### W ATER METEOROLOGICAL 

### S TATIONS



### ................................ .................. A

- 14

### OG&E iii Trinity Consultants

CALMET Processing Protocol 083701.0004 

## L IST OF 

## F IGURES

F IGURE 

### 1

- 1. P LOT OF 

### S OURCES AND 

### N EAREST 

### C LASS 

### I A REAS



### ................................ ......................... 1

- 3

F IGURE 

### 2

- 1. R EFINED 

### M ETEOROLOGICAL 

### M ODELING 

### D OMAIN



### ................................ ......................... 2

- 2

F IGURE 

### 3

- 1. P LOT OF 

### L AND 

### E LEVATION 

### U SING 

### USGS T ERRAIN 

### D ATA



### ................................ ............ 3

- 2

F IGURE 

### 3

- 2. P LOT OF 

### L AND 

### U SE 

### U SING 

### USGS LULC D ATA



### ................................ ............................. 3

- 3

F IGURE 

### 3

- 3. P LOT OF 

### S URFACE 

### S TATION 

### L OCATIONS



### ................................ ................................ ........ 3

- 5

F IGURE 

### 3

- 4. P LOT OF 

### U PPER 

### A IR 

### S TATIONS 

### L OCATIONS



### ................................ ................................ ... 3

- 6

F IGURE 

### 3

- 5. P LOT OF 

### P RECIPITATION METEORO LOGICAL 

### S TATIONS



### ................................ ................. 3

- 7

F IGURE 

### 3

- 6. P LOT OF 

### B UOY 

### M ETEOROLOGICAL 

### S TATIONS



### ................................ ................................ 3

- 8

### OG&E 1

- 1 Trinity Consultants

CALMET Processing Protocol 083701.0004 

## 1. I NTRODUCTION

Oklahoma Gas & Electric ( OG&E ) owns and operates three electric generating stations near Muskogee, Oklahoma (M uskogee Generat ing Station ) , Seminole, Oklahoma (Seminole Generating Station), and Stillwater, Oklahoma (Sooner Generating Station)

. The se generating stations are considered eligible to be regulated under the U.S. Environmental Protection Agency’s (EPA) Best

Available R etrofit Technology (BART) provisions of the Regional Haze Rule. This protocol describes the proposed methodology for conducting the CALMET data processing for the r efined

CALPUF F 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 B ES T 

## A VAILABLE 

## R ETROFIT 

## T ECHNOLOGY 

## R ULE 

## B ACKGROUND

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 a reas. 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, t he 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 foll owing

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

- eligi ble 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 det ermine 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

contri bute 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 O BJECTIVE

The objective of this document is to provide a protocol su mmarizing 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 conta ined 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 area s

. 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 98 th 

### 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 L OCATION OF 

## S OURCES AND 

## R ELEVANT 

## C LASS 

## I A REAS

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.

T ABLE 

### 1

- 1

. BART

- E LIGIBLE 

### S OURCE S

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 N atural 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 Guid elines, Class I areas within 300 km of each station

will be included in each analysis. The following table summarize s 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 station s . 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. No t e that the distances listed in the table below are
the distances between the stations and the closest border of the Class I areas.

T ABLE 

### 1

- 2

. D ISTANCE 

### F ROM 

### S TATION TO 

### S URROUNDING 

### C LASS 

### I A REAS

CACR HEGL UPBU WIMO

Muskogee 180 230 164 324

Seminole 2 42 386 310 178

Sooner 345 363 327 234

### OG&E 1

- 3 Trinity Consultants

CALMET Processing Protocol 083701.0004 A plot of the Class I areas with respect to the each station is provided in Figure 1

- 1.



### F IGURE 

### 1

- 1. P LOT OF 

### S OURCES AND 

### N EAREST 

### C LASS 

### I A REAS

### OG&E 2

- 1 Trinity Consultants

CALMET Processing Protocol 083701.0004 

## 2. CALPUFF M ODEL 

## S YSTEM

The main components of the CALPUFF modeling sy stem 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 transformatio n 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 M ODEL 

## V ERSIONS

The versions of the CALPUFF modeling system programs that are propos ed for conducting OG&E ’s

BART modeling are listed in Table 2

- 1. A deta iled refined CALPUFF BART modeling protocol will

be submitted in the near future.

T ABLE 

### 2

- 1. CALPUFF M ODELING 

### S YSTEM 

### V ERSIONS



### Processor Version Level

TERREL 3.3 030 402

CTGCOMP 2.21 030402

CTGPROC 2.63 050128

MAKEGEO 2.2 030402

CALMET 5.53a 040716

CA LPUFF 5.8 070623

POSTUTIL 1.3 030402

CALPOST 5.51 030709



## 2.2 M ODELING 

## D OMAIN

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 p oints 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 th at 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

### OG&E 2

- 2 Trinity Consultants

CALMET Processing Protocol 083701.0004 Figure 2

- 1 . The computati onal 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

t he 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 Longi tude 87.778 oW

. The meteorological grid spacing will be 4 km, resulting i n 462 grid p oints in the X direction and 376 grid points in the Y

direction.



### F IGURE 

### 2

- 1. R EFINED 

### M ETEOROLOGICAL 

### M ODELING 

### D OMAIN

- 800

- 600

- 400

- 200 0 200 400 600 800

LCC Easting (km) - 1600 - 1400 - 1200 - 1000 - 800 - 600 - 400 - 200

L C C N o r t h i n g ( k m ) Seminole Station Muskogee Station Sooner Station

WIMO C ACR UPBU HEGL

Class I Areas Meteorological Modeling Domain

Computational Modeling Domain 1

### OG&E 3

- 1 Trinity Consultants

CALMET Processing Protocol 083701.0004 

## 3. CALMET

T he EPA Approv ed 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, precipitati on measurements, mesoscale model output, and geophysical parameters into a single hourly, gridded data set for input in to CALPUFF. CALMET will be used to assimilate data for 2001

- 2003 using National Weather Service (NWS) surface station observations, upp er air station observations, precipitation station observations , buoy station observations (for overwater areas) , and mesoscale model output to develop the meteorological field.



## 3.1 G EOPHYSICAL 

## D ATA

CALMET requires geophysical data to characterize the terrai n 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 characteris tics such as surface roughness, albedo, Bowen ratio, and leaf

- area index that also effect turbulence and dispersion.



### 3.1.1 T ERRAIN 

### D ATA



### Terrain data will be obtained from the United States Geological Survey (USGS) in

1

- degree (1:250,000 scale or approximately 90 mete r 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 elevation s based on the

USGS data for the modeling domain is provided in Figure 3

- 1.

### OG&E 3

- 2 Trinity Consultants

CALMET Processing Protocol 083701.0004



### F IGURE 

### 3

- 1. P LOT OF 

### L AND 

### E LEVATION 

### U SING 

### USGS T ERRAIN 

### D ATA



### 3.1.2 L AND 

### U SE 

### D ATA



### The land use land cover (LULC) data from the USGS North American land cover

characteristics data base in the Lambert Azimuthal eq ual 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 - 140 0 - 1200 - 1000 - 800 - 600 - 400 - 200

L C C N o r t h i n g ( k m ) Seminole Station Muskogee Station Sooner Station

0 982 1960 2950 3930

Terrain Elevation (m)

### OG&E 3

- 3 Trinity Consultants

CALMET Processing Protocol 083701.0004



### F IGURE 

### 3

- 2. P LOT OF 

### L AND 

### U SE 

### U SING 

### USGS LULC D ATA



### 3.1.3 C OMPILING 

### T ERRAIN AND LAND 

### U SE 

### D ATA



### The terrain data files output by the TERELL program and the LULC f iles output by the CTGPROC program will be uploaded into the MAKEGEO program to create a geophysical data file that will be input in to CALMET.



## 3.2 M ETEOROLOGICAL 

## D ATA

CALMET will be used to assimilate data for 2001, 2002, and 2003 using mesoscale model outp ut and National Weather Service (NWS) surface station observations, upp er air station observations, precipitation station observations , and National Oceanic and Atmosphere Administrations (NOAA) buoy station observations to develop the meteorological field

.



### 3.2.1 M ESOSCALE 

### M ODEL 

### M ETEOROLOGICAL 

### D ATA



### 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 5 th 

### generation mesoscale model meteorological data sets (or M M5 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 8 00

LCC Easting (km) - 1600 - 1400 - 1200 - 1000 - 800 - 600 - 400 - 200

L C C N o r t h i n g ( k m )

10 27.5 45 62.5 80

Land Use Sooner Station

Muskogee Station

Seminole Station

### OG&E 3

- 4 Trinity Consultants

CALMET Processing Protocol 083701.0004

 2003 MM5 data set at 36 km resolution generated by the Midwest RPO

The specific MM5 data that will be use d 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 usin g 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 fil es that are broken into 10 to 11 day incre ments (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

file s (1 file per month)

. Note that the 2001 to 2003 MM5 d ata 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 Hou r 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 i n 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 period s covered in the files match CST.

Based on the above discussion, t he Alpine Geophysics MM5 data will not be used directly

. Instead the data fi les 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 file s occupy approximately 1.2 terabytes (TB) of hard drive space.



### 3.2.2 S URFACE 

### M ETEOROLOGICAL 

### D ATA



### Parameters affecting turbulent dispersion that are observed hourly at surface stations include wind speed and direction, temperature, cloud cover and ceiling, relati ve humidity, and precipitation type. It is OG&E ’s intent to use the surface stations listed in T able 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 th e 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.

### OG&E 3

- 5 Trinity Consultants

CALMET Processing Protocol 083701.0004



### F IGURE 

### 3

- 3. P LOT OF 

### S URFACE 

### S TATION 

### L OCATION S



### 3.2.3 U P PER 

### A IR 

### M ETEOROLOGICAL 

### D ATA



### 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 lau nched 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 b alloon 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 st ations 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 optim ize 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) - 1600 - 1400 - 1200 - 1000 - 80 0 - 600 - 400 - 200

L C C N o r t h i n g ( k m ) Seminole Station Muskogee Station Sooner Station

WIMO CACR UPBU HEGL

Class I Areas Surface Stations

### OG&E 3

- 6 Trinity Consultants

CALMET Processing Protocol 083701.0004



### F IGURE 

### 3

- 4. P LOT OF 

### U PPER 

### A IR 

### S TATIONS 

### L OCATIONS



### 3.2.4 P RECIPITATION 

### M ETEOROLOGICAL 

### D ATA



### The effects of chemical tra nsformation 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 thi s 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

rep resentation of the domain. Data from the stations will be processed for use in CALMET using EPA’s PMERGE program.

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### F IGURE 

### 3

- 5. P LOT OF 

### P RECIPITATION MET E OROLOGICAL 

### S TATIONS



### 3.2.5 B UOY 

### M ETEOROLOGICAL 

### D ATA



### 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 pr epared by filling missing hour records with the CALMET missing parameter value (9999). No adjustments to the data will occur.

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### F IGURE 

### 3

- 6. P LOT OF 

### B UOY 

### M ETEOROLOGICAL 

### S TATIONS



## 3.3 CALMET C ONTROL 

## P ARAMETERS

Appendix B provides a sample CALMET input fil e use d in OG&E ’s modeling analysis. A few details of the CALMET model setup for sensitive parameters are also discussed below.



### 3.3.1 V ERTICAL 

### M ETEOROLOGICAL 

### P ROFILE



### The height of the top vertical layer will be set to 3

, 500 meters . This height corresponds to

t he top sounding pressure level for which upper air observation data will be relied upon.

T he 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 weigh ted towards the surface to resolve the mixing layer while using a somewhat coarser resolution for the layers aloft.

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CALMET Processing Protocol 083701.0004 T ABLE 

### 3

- 1. V ERTICAL 

### L AYERS OF THE 

### CALMET M ETEOROLOGICAL 

### D OMAIN

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 tem perature 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. V alue s for

the bias factor may range fro m

- 1 to +1. A bias of

- 1 eliminate s upper

- air observations in

the 1/r 2 

### interpolations used to initialize the vertical wind fields

. Conversely

, a bias of +1

eliminate s the surface observations in the interpolations for this layer. Normally, bias is set

t o zero (0) for each vertical layer, such that the upper air and surface observations are given equal weight in the 1/r 2 

### interpolations. T he biases for each layer of the proposed modeling

domain will be set to zero.

CALMET allows for vertical extrapolatio n 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

con trols this setting is IEXT RP. 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., t he 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 I NFLUENCES OF 

### O BSERVATIONS



### Step 1 wind fields will be based on an initial guess using MM5 data and refined to reflect

terrain affects. Step 2 wind field s 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. R M AX1 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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CALMET Processing Protocol 083701.0004

wind field if th e 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 obs ervation data with respect to the MM 5 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 MM 5 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 wi ll 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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## A PPENDIX 

## A

- M ETEOROLOGICAL 

## S TATIONS

T ABLE 

### A

- 1. L IST OF 

### S URFACE METEOROLOG I CAL 

### S TAT IONS

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 KM EI 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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CALMET Processing Protocol 083701.0004

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 39.989 3

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 KSK F 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 131.4 78

- 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 96.99 96 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 KA FW 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

- 566.41 8

- 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

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CALMET Processing Protocol 083701.0004

Number Station

Acronym Station

ID LCC

East (km) LCC North

(km) Long Lat

84 KSV C 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 97.003 3 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

1 21 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 KLV S 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

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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

1 42 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 1 1164

- 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

- 9 40.981

- 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

- 324.56 9 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 9 6.9963 39.9857

### OG&E A

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CALMET Processing Protocol 083701.0004

T ABLE 

### A

- 2. L IST OF 

### U PPER 

### A IR METEOROLOGICAL 

### S TATIONS

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 9 51.609

- 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

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CALMET Processing Protocol 083701.0004

T ABLE 

### A

- 3. L IST OF 

### P RECIPITATION METEORO LOGICAL 

### S TATIONS

Number Sta tion

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 HA MT 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

- 91 5.326 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 36 920 509.943

- 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 96.993 6 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

3 7 TYE 57320

- 662.095

- 242.254 96.9922 39.9978

38 SAGU 57337

- 790.269

- 176.061 96.9907 39.9984

### OG&E A

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Number Sta tion

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

- 16 9.285 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 97.009 0 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

5 8 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 1227 38 842.476

- 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 97.0 006 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 Sta tion

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

- 29 2.133

- 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

- 181.1 77 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 WAL L 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 151 631 749.287

- 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 Sta tion

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

- 1 089.92 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 97.009 2 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 39.997 2

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 234 315 238.245

- 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 33 2.062

- 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 Sta tion

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

- 2 72.715 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 39.99 86

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 CL AY 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 DUR A 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 2 97610

- 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 Sta tion

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 29 9031

- 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 340 292

- 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

- 482.1 87 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 39.996 7

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 P AWN 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 3489 92 99.361

- 419.873 97.0012 39.9962

### OG&E A

- 12 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number Sta tion

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 710.0 48

- 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

- 476.4 14 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 97.008 0 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 39.9 924

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

2 64 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 H UST 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 415 661

- 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 Sta tion

Acronym Station

ID LCC

East
(km) LCC

North
(km) Long Lat

279 NEWB 416270 2 39.111

- 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

- 267.19 3 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

T ABLE 

### A

- 4. L IST OF 

### O VER 

### W ATER METEOR OLOGICAL 

### S TATIONS

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 687.9 84

- 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 Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

Date SO2

(tons) Avg. NOx Rate

(lb/MMBtu) NOx

(tons) Heat Input

(MMBtu)

1/1/2001 0.014 0.202 4.787 46,087

1/2/2001 0.015 0.2243 5.535 48,831

1/3/2001 0.016 0.2324 6.465 54,856

1/4/2001 0.015 0.2472 6.835 51,150

1/5/2001 0.015 0.2295 5.827 48,783

1/6/2001 0.014 0.2258 5.828 48,253

1/7/2001 0.01 0.161 2.72 32,070

1/8/2001 0.013 0.1819 4.203 41,767

1/9/2001 0.014 0.207 5.35 45,700

1/10/2001 0.013 0.1957 4.699 43,529

1/11/2001 0.012 0.1942 4.459 41,573

1/12/2001 0.015 0.2103 6.049 50,330

1/13/2001 0.013 0.1802 4.325 42,266

1/14/2001 0.009 0.148 2.24 30,269

1/15/2001 0.01 0.1638 2.999 34,364

1/16/2001 0.012 0.1739 3.935 41,489

1/17/2001 0.013 0.1896 4.397 41,694

1/18/2001 0.015 0.2143 5.91 51,559

1/19/2001 0.012 0.1832 3.987 40,093

1/20/2001 0.01 0.1459 2.602 32,991

1/21/2001 0.012 0.1796 4.014 41,428

1/22/2001 0.013 0.1769 4.102 42,797

1/23/2001 0.013 0.185 4.93 42,499

1/24/2001 0.01 0.145 2.436 32,177

1/25/2001 0.011 0.1736 3.66 37,899

1/26/2001 0.013 0.1962 5.122 43,715

1/27/2001 0.009 0.1487 2.3 29,992

1/28/2001 0.008 0.1265 1.786 28,231

1/29/2001 0.012 0.1878 4.319 39,764

1/30/2001 0.01 0.1594 2.883 33,206

1/31/2001 0.01 0.1529 2.646 32,017

2/5/2001 0.006 0.086 1.466 20,118

2/6/2001 0.016 0.2086 6.165 53,744

2/7/2001 0.009 0.1866 3.213 31,084

2/18/2001 0.001 0.0188 0.038 3,928

2/19/2001 0.007 0.0982 1.368 24,718

2/20/2001 0.009 0.1274 1.913 29,778

2/21/2001 0.01 0.1512 2.869 34,778

2/22/2001 0.017 0.2335 7.695 56,681

2/23/2001 0.012 0.1743 3.807 39,905

2/24/2001 0.009 0.1102 1.623 29,044

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

2/25/2001 0.009 0.13 1.917 29,477

2/26/2001 0.009 0.1329 2.099 30,616

2/27/2001 0.003 0.1306 0.7 10,554

3/4/2001 0.001 0.0184 0.034 3,433

3/5/2001 0.002 0.0515 0.267 7,045

3/6/2001 0.014 0.221 6.083 48,166

3/7/2001 0.015 0.1927 5.478 48,645

3/8/2001 0.012 0.1555 3.269 38,946

3/9/2001 0.015 0.1743 4.568 50,545

3/10/2001 0.011 0.1549 2.964 35,761

3/11/2001 0.01 0.1379 2.435 33,295

3/12/2001 0.012 0.158 3.691 39,661

3/13/2001 0.012 0.1647 3.496 39,647

3/14/2001 0.009 0.1211 1.73 28,569

3/15/2001 0.01 0.141 2.735 33,742

3/16/2001 0.009 0.1279 1.961 30,403

3/17/2001 0.011 0.1602 3.19 36,852

3/18/2001 0.009 0.119 1.786 29,585

3/19/2001 0.014 0.207 5.529 47,177

3/20/2001 0.018 0.2443 8.471 59,677

3/21/2001 0.012 0.1685 3.87 39,580

3/22/2001 0.01 0.142 2.625 33,865

3/23/2001 0.012 0.1767 4.124 40,557

3/24/2001 0.012 0.1817 4.169 40,503

3/25/2001 0.011 0.1617 3.538 37,819

3/26/2001 0.021 0.2919 11.813 68,929

3/27/2001 0.018 0.2611 8.918 60,896

3/28/2001 0.02 0.2639 10.097 67,036

3/29/2001 0.014 0.1788 4.609 45,838

3/30/2001 0.016 0.2006 5.744 52,185

3/31/2001 0.011 0.159 3.131 37,184

4/1/2001 0.013 0.1752 4.115 42,033

4/2/2001 0.02 0.2338 8.676 66,851

4/3/2001 0.02 0.2369 8.8 66,241

4/4/2001 0.017 0.2038 6.068 55,481

4/5/2001 0.018 0.2004 6.511 60,051

4/6/2001 0.016 0.1907 5.821 52,912

4/7/2001 0.018 0.2262 7.664 59,423

4/8/2001 0.018 0.2364 8.721 58,721

4/9/2001 0.023 0.2954 12.863 76,082

4/10/2001 0.019 0.2176 7.726 64,086

4/11/2001 0.018 0.2098 6.773 58,358

4/12/2001 0.016 0.2128 6.479 54,940

4/13/2001 0.013 0.1945 4.508 42,639

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

4/14/2001 0.013 0.1562 3.497 42,801

4/15/2001 0.012 0.1644 3.577 40,030

4/16/2001 0.018 0.251 9.291 61,371

4/17/2001 0.014 0.167 4.133 45,200

4/18/2001 0.016 0.2087 6.585 52,319

4/19/2001 0.016 0.1903 5.171 51,766

4/20/2001 0.015 0.1854 4.984 49,224

4/21/2001 0.018 0.217 7.923 60,062

4/22/2001 0.014 0.1674 4.429 45,026

4/23/2001 0.022 0.3043 13.43 74,361

4/24/2001 0.016 0.2062 5.866 52,154

4/25/2001 0.011 0.1527 3.108 37,695

4/26/2001 0.017 0.2286 7.555 56,092

4/27/2001 0.016 0.2169 7.077 51,677

4/28/2001 0.015 0.1953 5.461 48,962

4/29/2001 0.014 0.1772 4.859 47,124

4/30/2001 0.017 0.2 6.797 56,452

5/1/2001 0.023 0.3154 14.69 78,193

5/2/2001 0.022 0.2717 11.62 71,844

5/3/2001 0.018 0.2036 7.091 61,269

5/4/2001 0.016 0.2144 7.245 54,351

5/6/2001 0.002 0.0339 0.123 5,083

5/7/2001 0.015 0.1868 5.25 50,120

5/8/2001 0.011 0.1553 3.234 37,663

5/9/2001 0.017 0.2099 7.313 57,056

5/10/2001 0.021 0.2753 11.622 69,100

5/11/2001 0.015 0.2005 5.819 51,008

5/12/2001 0.014 0.1828 4.776 45,391

5/13/2001 0.012 0.189 4.196 39,970

5/14/2001 0.015 0.1792 5.128 50,519

5/15/2001 0.02 0.2335 9.346 65,047

5/16/2001 0.019 0.2378 9.333 63,118

5/17/2001 0.02 0.2367 8.716 66,585

5/18/2001 0.016 0.184 5.893 52,147

5/19/2001 0.014 0.167 4.463 45,811

5/20/2001 0.013 0.1558 3.867 44,248

5/21/2001 0.011 0.1592 3.108 37,242

5/22/2001 0.008 0.153 2.12 27,721

5/23/2001 0.012 0.1763 3.876 39,538

5/24/2001 0.01 0.1579 3.086 34,319

5/25/2001 0.009 0.1198 1.699 28,368

5/26/2001 0.013 0.1813 4.857 43,433

5/27/2001 0.013 0.1806 4.355 42,547

5/28/2001 0.011 0.1718 3.231 35,115

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

5/29/2001 0.013 0.1931 5.097 43,171

5/30/2001 0.012 0.1745 3.803 40,685

5/31/2001 0.01 0.1417 2.62 33,567

6/1/2001 0.012 0.1624 3.551 39,572

6/2/2001 0.015 0.1946 5.796 49,384

6/3/2001 0.013 0.1658 4.242 44,794

6/4/2001 0.015 0.1862 5.395 50,776

6/5/2001 0.014 0.1903 5.198 46,681

6/6/2001 0.01 0.1415 2.706 34,818

6/7/2001 0.01 0.147 2.676 34,163

6/8/2001 0.013 0.1805 4.463 44,347

6/9/2001 0.01 0.1477 2.744 33,898

6/10/2001 0.012 0.1572 3.357 38,638

6/11/2001 0.017 0.2095 7.511 57,735

6/12/2001 0.019 0.2257 8.151 62,453

6/13/2001 0.019 0.2262 8.396 63,287

6/14/2001 0.019 0.218 7.851 62,402

6/15/2001 0.017 0.2161 7.572 57,158

6/16/2001 0.017 0.2303 7.86 57,767

6/17/2001 0.015 0.1928 5.518 50,985

6/18/2001 0.011 0.154 3.944 37,549

6/19/2001 0.003 0.0882 0.39 8,841

7/4/2001 0 0.012 0.002 340

7/5/2001 0.007 0.0781 1.602 24,168

7/6/2001 0.017 0.2128 7.052 56,775

7/7/2001 0.018 0.2179 7.562 60,597

7/8/2001 0.012 0.1569 3.968 39,226

7/9/2001 0.006 0.0961 1.025 21,338

7/10/2001 0.012 0.1546 4.264 41,608

7/11/2001 0.019 0.2223 8.412 63,578

7/12/2001 0.013 0.1621 4.021 43,458

7/13/2001 0.011 0.157 3.255 37,270

7/14/2001 0.013 0.1955 4.735 42,380

7/15/2001 0.013 0.1699 4.156 41,999

7/16/2001 0.019 0.2452 9.083 61,972

7/17/2001 0.019 0.2417 9.109 64,826

7/18/2001 0.016 0.2237 8.871 53,151

7/19/2001 0.007 0.1258 2.653 23,336

7/20/2001 0.019 0.249 9.25 64,264

7/21/2001 0.02 0.2328 8.491 65,463

7/22/2001 0.02 0.2443 9.321 68,224

7/23/2001 0.02 0.224 8.157 65,909

7/24/2001 0.02 0.2445 9.159 67,299

7/25/2001 0.019 0.2355 8.694 64,989

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

7/26/2001 0.013 0.1794 4.211 43,236

7/27/2001 0.013 0.1774 4.508 44,375

7/28/2001 0.019 0.2528 10.205 63,064

7/29/2001 0.019 0.2475 9.877 63,148

7/30/2001 0.022 0.2758 12.376 71,671

7/31/2001 0.022 0.2781 12.547 72,866

8/1/2001 0.019 0.2373 9.073 62,425

8/2/2001 0.021 0.2795 12.222 69,430

8/4/2001 0.016 0.1885 7.963 54,373

8/5/2001 0.021 0.2535 11.118 69,392

8/6/2001 0.025 0.2972 15.248 84,978

8/7/2001 0.025 0.2612 12.576 82,822

8/8/2001 0.025 0.3036 14.997 82,983

8/9/2001 0.025 0.3064 14.974 82,680

8/10/2001 0.019 0.2215 8.202 63,423

8/12/2001 0.013 0.1633 5.452 44,824

8/13/2001 0.006 0.1483 1.688 19,487

8/14/2001 0.002 0.0623 0.246 5,337

8/15/2001 0.008 0.1385 2.604 25,423

8/16/2001 0.018 0.2429 8.743 60,910

8/17/2001 0.018 0.2434 9.046 60,599

8/18/2001 0.015 0.1771 4.996 50,262

8/19/2001 0.014 0.1915 5.261 48,081

8/20/2001 0.018 0.2217 8.411 61,514

8/21/2001 0.021 0.2575 11.024 69,191

8/22/2001 0.017 0.2267 7.102 55,132

8/23/2001 0.016 0.1806 5.129 51,909

8/24/2001 0.022 0.2213 8.506 72,974

8/25/2001 0.022 0.2256 8.811 72,126

8/26/2001 0.02 0.2177 7.642 65,753

8/27/2001 0.02 0.2303 7.848 66,030

8/28/2001 0.021 0.2293 8.581 70,504

8/29/2001 0.021 0.2264 8.509 71,148

8/30/2001 0.022 0.2056 7.903 72,119

8/31/2001 0.015 0.1776 4.423 48,572

9/4/2001 0.017 0.1992 8.364 57,635

9/5/2001 0.02 0.2337 9.682 65,332

9/6/2001 0.024 0.2887 13.929 80,508

9/7/2001 0.026 0.3046 15.043 87,673

9/8/2001 0.019 0.2353 8.989 64,371

9/9/2001 0.012 0.1626 3.702 40,954

9/10/2001 0.019 0.2765 11.064 64,465

9/11/2001 0.015 0.2078 5.686 49,648

9/12/2001 0.02 0.2698 11.86 67,987

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

9/13/2001 0.023 0.287 13.566 75,247

9/14/2001 0.015 0.2122 6.49 50,987

9/15/2001 0.012 0.1745 4.057 41,586

9/16/2001 0.01 0.1532 2.834 34,143

9/17/2001 0.018 0.2053 7.027 59,845

9/18/2001 0.017 0.1845 5.837 55,340

9/19/2001 0.02 0.29 12.096 67,446

9/20/2001 0.014 0.1873 5.165 48,024

9/21/2001 0.015 0.1985 5.829 50,294

9/22/2001 0.017 0.2183 7.653 56,805

9/23/2001 0.009 0.1337 2.095 30,464

9/24/2001 0.011 0.153 3.113 36,686

9/25/2001 0.009 0.1394 2.293 31,182

9/26/2001 0.009 0.1375 2.009 29,212

9/27/2001 0.013 0.1991 4.898 43,804

9/28/2001 0.011 0.1601 3.348 38,249

9/29/2001 0.009 0.1273 1.879 29,507

9/30/2001 0.009 0.1299 1.915 29,494

10/1/2001 0.016 0.2279 7.078 54,478

10/2/2001 0.02 0.2719 10.453 67,704

10/3/2001 0.021 0.2808 11.517 70,491

10/4/2001 0.018 0.217 7.058 59,238

10/5/2001 0.017 0.2193 6.911 58,101

10/6/2001 0.011 0.1701 3.541 37,099

10/7/2001 0.012 0.173 4.088 40,906

10/8/2001 0.018 0.2333 7.922 60,878

10/9/2001 0.021 0.2618 10.653 71,124

10/10/2001 0.025 0.3041 14.046 84,843

10/11/2001 0.022 0.2695 10.787 72,705

10/12/2001 0.014 0.1858 4.721 46,018

10/13/2001 0.009 0.1202 1.806 30,005

10/14/2001 0.009 0.1397 2.083 29,826

10/15/2001 0.014 0.1868 4.97 46,963

10/16/2001 0.015 0.1948 5.346 50,101

10/17/2001 0.014 0.1865 5.001 46,094

10/18/2001 0.015 0.2042 5.707 49,980

10/19/2001 0.016 0.1879 5.568 54,454

10/20/2001 0.011 0.1695 3.665 38,306

10/21/2001 0.014 0.2021 5.378 46,550

10/22/2001 0.017 0.2118 7.204 57,917

10/23/2001 0.019 0.2224 8.303 64,766

10/24/2001 0.02 0.2506 9.924 68,044

10/25/2001 0.014 0.1916 4.787 46,344

10/26/2001 0.012 0.1569 3.256 39,305

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

10/27/2001 0.014 0.1796 4.434 45,299

10/28/2001 0.012 0.1632 3.641 40,671

10/29/2001 0.019 0.2607 9.652 64,118

10/30/2001 0.012 0.1614 3.716 41,285

10/31/2001 0.007 0.1413 1.716 22,574

11/2/2001 0.001 0.005 0.006 2,211

11/3/2001 0.012 0.1404 3.282 38,466

11/4/2001 0.009 0.1343 2.105 30,533

11/5/2001 0.017 0.2186 6.839 55,453

11/6/2001 0.019 0.2791 9.677 62,493

11/7/2001 0.022 0.3063 13.163 74,177

11/8/2001 0.016 0.226 6.573 53,905

11/9/2001 0.017 0.2095 6.302 56,263

11/10/2001 0.011 0.1513 2.83 35,031

11/11/2001 0.009 0.1295 1.881 29,044

11/12/2001 0.023 0.3233 14.175 76,017

11/13/2001 0.018 0.2403 8.093 59,969

11/14/2001 0.022 0.32 13.545 73,986

11/15/2001 0.019 0.2603 9.307 64,252

11/16/2001 0.02 0.2591 9.545 66,804

11/17/2001 0.015 0.2233 6.084 49,215

11/18/2001 0.01 0.1308 2.387 33,118

11/19/2001 0.015 0.1822 4.938 50,936

11/20/2001 0.014 0.181 4.702 46,801

11/21/2001 0.013 0.1629 3.929 42,621

11/28/2001 0.002 0.0235 0.15 7,641

11/29/2001 0.014 0.1843 4.9 47,614

11/30/2001 0.013 0.154 3.552 42,054

12/1/2001 0.013 0.1705 3.903 41,932

12/2/2001 0.011 0.1418 2.96 36,214

12/3/2001 0.012 0.1432 3.148 40,199

12/4/2001 0.009 0.1379 2.27 31,592

12/24/2001 0.002 0.0137 0.043 6,050

12/25/2001 0.01 0.1203 2.38 34,423

12/26/2001 0.013 0.1618 4.148 43,510

12/27/2001 0.014 0.1483 3.732 45,410

12/28/2001 0.011 0.1311 2.488 35,588

12/29/2001 0.011 0.1445 3.136 37,497

12/30/2001 0.015 0.1716 4.954 48,976

12/31/2001 0.012 0.1348 2.943 39,026

1/1/2002 0.011 0.1289 2.741 37,107

1/2/2002 0.019 0.2159 7.77 62,305

1/3/2002 0.014 0.1767 4.509 47,734

1/4/2002 0.013 0.1619 3.518 42,761

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

1/5/2002 0.015 0.1869 4.642 49,164

1/6/2002 0.011 0.1285 2.462 35,085

1/7/2002 0.014 0.1835 4.424 46,324

1/8/2002 0.012 0.1583 3.56 41,383

1/9/2002 0.009 0.1222 1.888 28,489

2/9/2002 0.016 0.011 0.296 52,507

2/10/2002 0.02 0.0207 0.606 66,669

2/11/2002 0.011 0.1331 2.365 36,624

2/12/2002 0.011 0.1611 3.084 36,846

2/13/2002 0.01 0.1785 3.229 34,397

2/14/2002 0.013 0.2097 4.987 43,360

2/15/2002 0.014 0.2086 5.029 45,459

2/16/2002 0.012 0.2087 4.505 41,526

2/17/2002 0.01 0.1814 2.984 31,880

2/18/2002 0.011 0.1988 3.921 37,465

2/19/2002 0.014 0.1981 4.872 45,380

2/20/2002 0.014 0.2173 5.256 45,213

2/21/2002 0.017 0.2381 6.925 55,851

2/22/2002 0.014 0.2127 5.232 46,535

2/23/2002 0.014 0.2037 4.945 46,575

2/24/2002 0.01 0.1896 3.281 32,913

2/25/2002 0.009 0.1759 2.747 30,582

2/26/2002 0.012 0.1834 3.845 41,052

2/27/2002 0.013 0.1826 3.942 42,493

2/28/2002 0.01 0.1566 2.711 34,015

3/1/2002 0.006 0.2166 2.028 18,483

3/15/2002 0.002 0.0235 0.123 7,253

3/16/2002 0.015 0.2207 5.787 49,573

3/17/2002 0.013 0.2006 4.429 42,117

3/18/2002 0.015 0.2198 5.663 49,072

3/19/2002 0.013 0.2061 4.707 42,893

3/20/2002 0.014 0.2145 5.842 47,868

3/21/2002 0.018 0.2544 8.371 59,345

3/22/2002 0.018 0.2707 9.128 58,545

3/23/2002 0.011 0.192 3.909 37,607

3/24/2002 0.011 0.1744 3.501 37,051

3/25/2002 0.019 0.2433 8.382 62,097

3/26/2002 0.018 0.2377 7.865 60,967

3/27/2002 0.014 0.2157 5.6 47,319

3/31/2002 0.001 0.0128 0.016 2,498

4/1/2002 0.012 0.1843 4.136 40,687

4/2/2002 0.014 0.2243 5.561 46,508

4/3/2002 0.015 0.2472 6.462 49,758

4/4/2002 0.014 0.2277 6.031 48,076

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

4/5/2002 0.012 0.2001 4.283 40,215

4/6/2002 0.011 0.191 3.747 37,023

4/7/2002 0.011 0.1853 3.678 36,988

4/8/2002 0.009 0.1468 2.22 30,245

4/9/2002 0.01 0.172 2.907 32,815

4/10/2002 0.013 0.2167 4.962 43,831

4/11/2002 0.016 0.2274 6.512 54,319

4/12/2002 0.016 0.2247 6.09 51,709

4/13/2002 0.017 0.2069 6.17 55,381

4/14/2002 0.013 0.1926 4.747 44,077

4/15/2002 0.018 0.2423 7.569 59,682

4/16/2002 0.019 0.2365 7.739 63,103

4/17/2002 0.02 0.2336 8.481 67,506

4/18/2002 0.018 0.224 7.316 61,168

4/19/2002 0.02 0.2517 8.836 65,022

5/2/2002 0.001 0.0148 0.017 2,211

5/3/2002 0.007 0.0993 1.714 24,898

5/4/2002 0.012 0.1863 3.914 40,781

5/5/2002 0.011 0.1728 3.337 37,451

5/6/2002 0.018 0.2097 6.908 59,594

5/7/2002 0.019 0.2303 8.425 64,152

5/8/2002 0.023 0.2361 9.35 75,224

5/9/2002 0.016 0.2122 5.898 52,439

5/10/2002 0.013 0.1986 4.614 44,164

5/11/2002 0.014 0.1765 4.683 47,444

5/12/2002 0.017 0.191 5.519 55,482

5/13/2002 0.009 0.1702 2.581 30,206

5/14/2002 0.009 0.161 2.348 29,134

5/15/2002 0.011 0.173 3.44 37,392

5/16/2002 0.021 0.2479 9.731 69,029

5/17/2002 0.012 0.2209 5.043 41,299

5/18/2002 0.01 0.188 3.206 33,448

5/19/2002 0.009 0.1645 2.379 28,929

5/20/2002 0.004 0.1594 1.021 12,647

6/1/2002 0.002 0.0113 0.034 5,847

6/2/2002 0.019 0.2273 9.398 63,706

6/3/2002 0.024 0.2836 13.792 81,176

6/4/2002 0.022 0.2306 9.943 73,180

6/5/2002 0.018 0.2241 7.916 61,459

6/6/2002 0.015 0.1971 5.382 48,636

6/7/2002 0.013 0.1934 4.553 43,848

6/8/2002 0.015 0.186 4.854 49,505

6/9/2002 0.013 0.1597 3.658 44,556

6/10/2002 0.017 0.1751 5.207 55,339

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

6/11/2002 0.016 0.1805 5.309 53,865

6/12/2002 0.017 0.1882 5.673 55,975

6/13/2002 0.017 0.1988 6.108 56,375

6/14/2002 0.011 0.1794 3.37 36,087

6/15/2002 0.013 0.1893 4.432 44,130

6/16/2002 0.011 0.169 3.104 35,720

6/17/2002 0.014 0.2101 5.291 47,773

6/18/2002 0.014 0.2049 5.253 47,076

6/19/2002 0.016 0.1944 5.498 52,049

6/20/2002 0.016 0.1911 5.7 54,348

6/21/2002 0.016 0.1905 5.506 53,336

6/22/2002 0.016 0.1816 5.251 54,099

6/23/2002 0.018 0.2016 6.77 59,249

6/24/2002 0.022 0.2445 10.128 72,397

6/25/2002 0.022 0.2426 10.262 72,043

6/26/2002 0.018 0.1814 5.963 60,244

6/27/2002 0.015 0.1849 4.94 50,555

6/28/2002 0.015 0.1851 5.1 51,646

6/29/2002 0.021 0.2412 9.898 69,078

6/30/2002 0.021 0.2355 9.247 68,381

7/1/2002 0.019 0.2164 7.691 64,385

7/2/2002 0.018 0.197 6.338 59,640

7/3/2002 0.017 0.1985 6.01 55,029

7/4/2002 0.019 0.2203 7.709 62,456

7/5/2002 0.021 0.2533 10.409 70,091

7/6/2002 0.021 0.2369 9.529 69,859

7/7/2002 0.02 0.2567 10.354 68,153

7/8/2002 0.024 0.2977 13.867 78,883

7/9/2002 0.022 0.2421 10.008 73,374

7/10/2002 0.019 0.2155 7.915 64,969

7/11/2002 0.006 0.1143 1.23 18,875

7/12/2002 0.013 0.168 3.94 43,917

7/13/2002 0.013 0.1685 3.834 43,460

7/14/2002 0.013 0.1713 3.981 42,789

7/15/2002 0.018 0.2131 7.348 59,142

7/16/2002 0.016 0.1863 5.406 53,142

7/17/2002 0.015 0.1769 4.941 51,354

7/18/2002 0.013 0.1603 3.517 42,566

7/19/2002 0.015 0.1703 4.591 50,001

7/20/2002 0.019 0.2103 7.674 63,309

7/21/2002 0.02 0.211 8.165 66,038

7/22/2002 0.018 0.1994 6.706 59,449

7/23/2002 0.017 0.1995 6.439 56,379

7/24/2002 0.014 0.1683 4.345 47,462

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

7/25/2002 0.018 0.2057 7.026 59,366

7/26/2002 0.019 0.2195 7.913 61,670

7/27/2002 0.02 0.2344 9.085 65,785

7/28/2002 0.02 0.2329 9.219 66,319

7/29/2002 0.018 0.2211 7.091 60,135

7/30/2002 0.019 0.1987 7.016 62,413

7/31/2002 0.02 0.2116 8.065 67,140

8/1/2002 0.02 0.2348 9.19 67,723

8/2/2002 0.02 0.2204 8.544 65,919

8/3/2002 0.021 0.233 9.727 71,119

8/4/2002 0.022 0.2389 10.048 72,709

8/5/2002 0.023 0.2528 11.034 76,430

8/6/2002 0.022 0.2487 10.381 72,419

8/7/2002 0.02 0.2277 8.971 66,020

8/8/2002 0.016 0.1953 5.712 54,134

8/9/2002 0.02 0.2207 8.389 66,924

8/10/2002 0.019 0.2229 8.173 63,200

8/11/2002 0.019 0.2428 9.007 64,645

8/12/2002 0.019 0.2223 8.197 63,315

8/13/2002 0.015 0.177 4.992 51,591

8/14/2002 0.013 0.1615 3.639 44,028

8/15/2002 0.014 0.1525 3.574 45,965

8/16/2002 0.014 0.178 4.527 47,668

8/17/2002 0.02 0.2145 8.039 66,775

8/18/2002 0.021 0.2241 9.121 71,329

8/19/2002 0.022 0.2147 8.779 72,190

8/20/2002 0.019 0.2123 8 64,039

8/21/2002 0.021 0.2276 9.215 69,432

8/22/2002 0.021 0.2321 9.377 71,456

8/23/2002 0.023 0.235 9.958 75,098

8/24/2002 0.023 0.2532 10.574 78,007

8/25/2002 0.003 0.1184 0.839 9,352

8/26/2002 0.016 0.1796 6.672 54,640

8/27/2002 0.018 0.2074 7.099 59,167

8/28/2002 0.017 0.2014 7.045 57,669

8/29/2002 0.015 0.1921 5.529 51,098

8/30/2002 0.017 0.2171 7.671 57,804

8/31/2002 0.015 0.1841 5.165 51,198

9/1/2002 0.014 0.1783 4.742 48,187

9/2/2002 0.02 0.2379 9.75 67,051

9/3/2002 0.022 0.2633 11.663 74,026

9/4/2002 0.022 0.2336 10.178 73,496

9/5/2002 0.021 0.2239 9.081 69,350

9/6/2002 0.019 0.2164 8.132 63,607

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

9/7/2002 0 0.142 0.077 1,086

9/8/2002 0.002 0.0866 0.477 7,847

9/9/2002 0.02 0.2438 9.69 68,073

9/10/2002 0.022 0.2685 12.292 74,588

9/11/2002 0.02 0.2608 10.642 66,892

9/12/2002 0.017 0.227 7.805 55,975

9/13/2002 0.016 0.2185 6.919 54,441

9/14/2002 0.017 0.201 6.647 58,026

9/15/2002 0.015 0.1733 4.41 48,560

9/16/2002 0.015 0.1741 4.554 49,299

9/17/2002 0.014 0.1813 4.473 46,893

9/18/2002 0.019 0.2025 7.282 62,050

9/19/2002 0.015 0.1645 4.117 48,986

9/20/2002 0.016 0.1949 5.813 54,811

9/21/2002 0.017 0.2213 7.779 57,523

9/22/2002 0.015 0.1887 4.946 48,475

9/23/2002 0.017 0.2053 6.094 57,656

9/24/2002 0.009 0.1612 2.532 31,042

9/25/2002 0.009 0.1522 2.184 28,696

9/26/2002 0.009 0.1447 2.192 30,380

9/27/2002 0.016 0.1781 5.067 53,614

9/28/2002 0.02 0.2236 9.112 65,596

9/29/2002 0.018 0.2112 7.366 58,893

9/30/2002 0.024 0.2666 12.481 79,285

10/1/2002 0.02 0.22 8.269 65,225

10/2/2002 0.017 0.1763 5.171 55,756

10/3/2002 0.01 0.148 2.42 32,066

10/4/2002 0.024 0.2682 12.474 81,557

10/5/2002 0.02 0.2543 9.726 68,123

10/6/2002 0.021 0.2488 10.73 70,725

10/7/2002 0.017 0.2079 6.327 55,178

10/8/2002 0.009 0.1534 2.324 30,329

10/9/2002 0.011 0.1682 3.296 37,760

10/10/2002 0.011 0.1739 3.359 37,865

10/11/2002 0.013 0.1826 3.949 42,777

10/12/2002 0.016 0.1726 4.821 52,701

10/13/2002 0.012 0.1787 3.52 38,416

10/14/2002 0.014 0.1891 4.577 45,296

10/15/2002 0.011 0.1567 2.851 35,609

10/16/2002 0.012 0.1799 3.735 39,422

10/17/2002 0.009 0.1603 2.453 28,618

10/20/2002 0.002 0.0122 0.036 5,771

10/21/2002 0.018 0.2094 7.817 62,036

10/22/2002 0.02 0.2096 7.478 65,071

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

10/23/2002 0.013 0.1826 4.527 44,437

10/24/2002 0.015 0.1721 4.372 49,483

10/25/2002 0.014 0.1658 4.185 47,824

10/26/2002 0.011 0.1546 2.944 35,938

10/27/2002 0.013 0.1601 3.608 43,240

10/28/2002 0.02 0.2088 7.729 65,115

10/29/2002 0.016 0.194 5.532 54,367

10/30/2002 0.015 0.188 4.794 48,862

10/31/2002 0.011 0.1581 2.904 35,231

11/1/2002 0.011 0.1485 2.819 36,574

11/2/2002 0.01 0.145 2.383 31,903

11/3/2002 0.011 0.1482 2.848 35,811

11/4/2002 0.023 0.2648 12.133 78,254

11/5/2002 0.021 0.2342 9.378 68,889

11/6/2002 0.015 0.1738 4.608 49,173

11/7/2002 0.02 0.2313 8.749 65,161

11/8/2002 0.017 0.1781 5.178 56,524

11/9/2002 0.009 0.136 2.161 31,346

11/10/2002 0.01 0.1448 2.362 31,887

11/11/2002 0.013 0.1856 4.725 44,136

2/14/2003 0.001 0.015 0.013 1,699

2/16/2003 0.001 0.008 0.018 4,605

2/17/2003 0.017 0.007 0.196 55,932

2/18/2003 0.012 0.1238 2.05 41,073

2/19/2003 0.003 0.1366 0.708 9,395

3/28/2003 0.002 0.0242 0.107 7,599

3/29/2003 0.013 0.1843 4.455 44,910

3/30/2003 0.011 0.1648 3.195 37,684

3/31/2003 0.011 0.1599 3.049 37,123

4/1/2003 0.009 0.1645 2.533 30,638

4/2/2003 0.009 0.1578 2.455 30,591

4/3/2003 0.006 0.1202 1.32 19,515

4/4/2003 0.005 0.102 0.967 15,489

4/5/2003 0.009 0.1568 2.442 30,236

4/6/2003 0.009 0.1436 2.17 29,975

4/7/2003 0.011 0.15 3.071 37,476

4/8/2003 0.012 0.1548 3.05 38,738

4/9/2003 0.015 0.1841 5.177 50,011

4/10/2003 0.01 0.141 2.445 34,069

4/11/2003 0.009 0.1414 2.113 29,972

4/12/2003 0.009 0.1431 2.162 30,296

4/13/2003 0.008 0.1405 1.976 28,127

4/14/2003 0.01 0.1486 2.56 33,621

4/15/2003 0.007 0.1452 1.758 24,188

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

4/25/2003 0.003 0.0553 0.492 11,035

4/26/2003 0.01 0.1436 2.364 32,877

4/27/2003 0.01 0.1418 2.309 31,985

4/28/2003 0.008 0.1336 1.711 25,610

5/9/2003 0.004 0.0611 0.614 12,647

5/10/2003 0.017 0.2021 6.54 57,405

5/11/2003 0.01 0.1643 2.778 32,877

5/12/2003 0.01 0.17 3.027 34,463

5/13/2003 0.01 0.1454 2.497 33,067

5/14/2003 0.008 0.1238 1.727 27,904

5/15/2003 0.009 0.1203 1.765 28,349

5/16/2003 0.009 0.129 2.082 31,551

5/17/2003 0.008 0.1178 1.644 27,919

5/18/2003 0.01 0.1452 2.588 34,093

5/19/2003 0.016 0.1815 4.992 51,799

5/20/2003 0.004 0.1189 0.738 11,975

6/1/2003 0.002 0.0204 0.091 7,884

6/2/2003 0.01 0.125 2.122 33,776

6/3/2003 0.009 0.1308 1.946 29,693

6/4/2003 0.01 0.1464 2.454 32,222

6/5/2003 0.007 0.1192 1.338 21,933

6/6/2003 0.007 0.1182 1.317 21,747

6/7/2003 0.006 0.1135 1.1 19,380

6/8/2003 0.006 0.1165 1.136 19,497

6/9/2003 0.002 0.1092 0.387 6,865

6/30/2003 0.002 0.0148 0.051 6,666

7/1/2003 0.01 0.1128 1.846 32,090

7/2/2003 0.01 0.1271 2.185 32,181

7/3/2003 0.01 0.136 2.453 33,123

7/4/2003 0.006 0.0813 1.036 21,649

7/5/2003 0.007 0.1085 1.225 21,943

7/6/2003 0.009 0.1127 1.813 29,175

7/7/2003 0.012 0.138 3.41 40,692

7/8/2003 0.011 0.1252 2.581 36,435

7/9/2003 0.01 0.1078 2.01 34,360

7/10/2003 0.007 0.1007 1.228 23,077

7/11/2003 0.01 0.1343 2.455 33,518

7/12/2003 0.01 0.1307 2.379 32,929

7/13/2003 0.009 0.1247 1.94 29,003

7/14/2003 0.013 0.1405 3.51 43,006

7/15/2003 0.015 0.185 4.892 50,793

7/16/2003 0.014 0.1793 5.3 47,457

7/17/2003 0.013 0.1686 3.913 42,782

7/18/2003 0.013 0.165 4.07 43,826

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

7/19/2003 0.008 0.1224 1.76 25,804

7/20/2003 0.01 0.1375 2.73 34,139

7/21/2003 0.013 0.1501 3.85 44,737

7/22/2003 0.006 0.103 1.121 21,104

7/23/2003 0.006 0.1008 1.011 19,929

7/24/2003 0.006 0.1075 1.072 19,935

7/25/2003 0.009 0.1438 2.495 31,066

7/26/2003 0.011 0.1486 3.135 35,801

7/27/2003 0.013 0.173 5.431 44,064

7/28/2003 0.017 0.2069 6.998 58,049

7/29/2003 0.011 0.1515 3.021 36,394

7/30/2003 0.007 0.1108 1.516 24,235

7/31/2003 0.009 0.1397 2.345 31,381

8/1/2003 0.01 0.1266 2.392 34,091

8/2/2003 0.006 0.092 0.892 19,398

8/3/2003 0.006 0.0904 0.875 19,360

8/4/2003 0.009 0.1192 2.303 30,760

8/5/2003 0.01 0.1227 2.572 34,455

8/6/2003 0.008 0.1203 1.763 26,244

8/7/2003 0.008 0.1309 1.829 25,444

8/8/2003 0.008 0.1298 2.097 27,401

8/9/2003 0.007 0.1191 1.409 22,463

8/10/2003 0.006 0.1079 1.061 19,660

8/11/2003 0.006 0.1075 1.061 19,738

8/12/2003 0.006 0.1095 1.08 19,725

8/13/2003 0.006 0.1065 1.048 19,690

8/14/2003 0.008 0.1326 2.107 28,151

8/15/2003 0.01 0.1322 2.58 33,848

8/16/2003 0.013 0.1526 3.956 42,216

8/17/2003 0.013 0.1577 4.289 43,090

8/18/2003 0.014 0.1655 4.59 47,382

8/19/2003 0.014 0.1708 5.163 46,902

8/20/2003 0.015 0.1618 5.32 49,507

8/21/2003 0.014 0.1881 5.674 48,299

8/22/2003 0.012 0.166 3.744 41,589

8/23/2003 0.01 0.1376 2.684 32,518

8/24/2003 0.01 0.1334 2.577 33,755

8/25/2003 0.014 0.1732 4.318 45,380

8/26/2003 0.013 0.1547 3.525 42,822

8/27/2003 0.01 0.1459 2.67 33,331

8/28/2003 0.01 0.1498 2.62 32,451

8/29/2003 0.013 0.1693 3.995 43,374

8/30/2003 0.012 0.1627 3.506 40,500

8/31/2003 0.006 0.0985 0.948 19,262

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

9/1/2003 0.01 0.1333 2.529 33,302

9/2/2003 0.008 0.1248 1.888 27,757

9/3/2003 0.008 0.1173 1.595 25,074

9/4/2003 0.008 0.1225 1.797 26,458

9/5/2003 0.006 0.105 1.099 20,221

9/6/2003 0.006 0.1046 1.019 19,416

9/7/2003 0.006 0.1108 1.228 21,382

9/8/2003 0.009 0.1403 2.307 29,597

9/9/2003 0.01 0.1442 2.718 32,493

9/10/2003 0.009 0.1393 2.427 30,284

9/11/2003 0.008 0.126 1.829 26,313

9/12/2003 0.006 0.1015 0.992 19,325

9/13/2003 0.009 0.1308 2.093 28,954

9/14/2003 0.007 0.1298 1.696 24,158

9/15/2003 0.007 0.129 1.71 24,800

9/16/2003 0.007 0.1279 1.697 24,474

9/17/2003 0.007 0.1288 1.716 24,273

9/18/2003 0.007 0.1259 1.509 22,736

9/19/2003 0.006 0.1163 1.157 19,547

9/20/2003 0.008 0.1318 1.753 25,392

9/21/2003 0.007 0.1188 1.465 23,212

9/22/2003 0.01 0.1355 2.401 34,680

9/23/2003 0.009 0.1447 2.381 31,309

9/24/2003 0.01 0.1484 2.635 34,458

9/25/2003 0.01 0.1461 2.608 32,192

9/26/2003 0.011 0.1719 3.773 37,670

9/27/2003 0.012 0.1762 4.114 40,712

9/28/2003 0.006 0.1263 1.249 19,773

9/29/2003 0.006 0.1286 1.388 21,146

9/30/2003 0.007 0.1355 1.688 23,273

10/1/2003 0.006 0.1358 1.542 21,627

10/5/2003 0.002 0.0366 0.114 5,808

10/6/2003 0.01 0.1548 2.763 32,216

10/7/2003 0.013 0.1837 4.234 44,450

10/8/2003 0.009 0.156 2.64 30,400

10/18/2003 0 0.0105 0.007 1,196

10/19/2003 0.009 0.1316 2.367 28,415

10/20/2003 0.015 0.1955 5.096 51,193

10/21/2003 0.017 0.2215 7.467 57,794

10/22/2003 0.028 0.3428 16.509 93,036

10/23/2003 0.025 0.2927 12.561 82,673

10/24/2003 0.024 0.2452 9.877 79,990

10/25/2003 0.03 0.3455 17.916 98,845

10/26/2003 0.023 0.2924 12.033 78,223

### Entergy Arkansas, Inc.

Lake Catherine - Unit 4

CEMS Data from CAMD

10/27/2003 0.012 0.1688 3.629 38,963

10/28/2003 0.012 0.1751 3.723 38,838

10/29/2003 0.01 0.1726 3.271 34,783

10/30/2003 0.008 0.1362 1.893 25,485

10/31/2003 0.005 0.1143 1.042 17,440

11/9/2003 0.002 0.0359 0.172 7,344

11/10/2003 0.006 0.1283 1.306 20,363

11/11/2003 0.026 0.3002 15.338 85,158

11/12/2003 0.037 0.4825 29.477 122,153

11/13/2003 0.02 0.3162 14.539 67,701

11/14/2003 0.016 0.2494 9.144 53,543

11/15/2003 0.023 0.309 14.475 76,658

11/16/2003 0.014 0.2057 7.065 47,591

11/17/2003 0.011 0.1664 3.785 37,220

11/18/2003 0.004 0.1328 0.842 11,838

12/11/2003 0.001 0.024 0.051 3,992

12/12/2003 0.008 0.1213 1.843 25,998

12/13/2003 0.009 0.137 2.2 28,738

12/14/2003 0.006 0.118 1.209 20,460
12/15/2003 0.009 0.1466 2.348 30,084 Max (tpd) --> 0.037 29.477 Max (lb/hr) --> 3.1 2456.4

Note: Dates with no operation/emissions not shown

### Entergy Trinity Consultants

BART Analysis

– Lake Catherine 

## A PPENDIX D



### S ARGENT 

### & L UNDY 

### NO X 

### C ONTROL 

### T ECHNOLOGY 

### S TUDY

# 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 th e 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 lim itations, budgetary and time constraints, and business

objectives of the Client; (2) information and data pr ovided 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 th is 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 NO X 

### EMISSION RATES ..............................................3

2. WHITE BLUFF - UNITS 1 & 2.....................................................................................................4

2.1. FUEL SWITCHIN G 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-Cata lytic Reduction .............................................................................................. ..6

2.3.2. Selective Catalytic Reduction.................................................................................................. .......7

2.4. CAPITAL COSTS.................................................................................................................. ........8

2.5. OPERATING AND MAIN TENANCE 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-Cata lytic 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-Cata lytic 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 MAINTENAN CE 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 El rod 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 Auxilia ry Boiler, and Lake Catherine – Unit 4. The

information developed in this st udy 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, tangen tially-fired, pulverized-coal fueled units, rated at

815 MWnet and 844 MWnet respectively. Powder River B asin 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 industria l boiler capable of producing 140,000 lb/hr of steam,

used for startup of the White Bluff coal units. Th e 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, tangen tially-fired, natural gas fueled unit, capable of

generating 558 MWnet. The unit was originally designe d as a dual-fuel unit, able to use natural gas or

No. 2 Fuel Oil as fuel. This evaluation will be for na tural 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.

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1.3. ESTIMATE METHODOLOGY

1.3.1. Capital Cost Estimates

S&L’s capital cost estimates for retrofit NOx contro l 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 assumpti on is that the project will be implemented on a

multiple-contracting basis. The capital cost estimates pr ovided 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 si ze of the project. License fees and royalties are not

expected for the proposed control strategies. The Basi s of Estimate and capital costs are summarized in

Appendix A.

Capital cost estimates were calculated in one of thr ee 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 s ituations 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 de veloped from similar projects that Sargent & Lundy

has completed and adjusted for unit size.

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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 co mpleted. 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 Maintena nce 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 NO X 

### EMISSION RATES

NOx control systems retrofit onto existing coal or g as-fired boilers are typically designed to achieve

varying levels of NOx removal efficiencies fro m 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 necessar ily 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, NH 3 

### :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 th at a NOx control technology vendor would be willing

to guarantee. Based on engineering judgment, and taki ng into consideration emissions data from existing

coal- and gas-fired sources, a co mpliance margin above the design ta rget is recommended for high

removal efficiency/low emission rate technologies (suc h 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 shor ter-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

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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 reducti ons. The nearest natural gas pipeline to the White

Bluff facility is approximately 20 miles away. Constr uction of a pipeline is currently estimated at $2M

per mile resulting in a cost of $40M to bring natura l 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. Un its 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 cont rolling both the stoichiometric and temperature

profiles of the combustion flame in each burner flame envelope. Control is achieved with design features

that regulate the aerodynamic distribution and mixing of the fuel and air, yielding reduced oxygen (O 2 

### ) in

the primary combustion zone, reduced flame temperatur e, 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 mi xture that is fed to the burners reduces the flame

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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 a nd 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 natu ral gas and propane, since

FGR is more effective in controlling thermal NOx rath er than fuel NOx. Industry experience with FGR on

coal-fired units for steam temperature control has s hown very high maintenance on the gas recirculation

fans due to erosion and corrosion. Many of the un its with FGR for steam temperature control have

removed the recirculation fans from service. The NO x control achievable on tangentially fired units like

White Bluff – Units 1&2 with LNB+OFA has been comp arable 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 histor ical 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 ra te at White Bluff – Units 1&2. The reprogrammed

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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 informati on available from vendors, it is expected that Neural

Network technology on a coal-fired boiler can mainta in 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 est imated 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 (NH 3 

### ) or urea

(CO(NH 2 

### ) 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 N 2 

### and water as shown in the following

equations:

(CO(NH 2 

### ) 2 

### ) + 2NO + 1⁄2O 2 

### → 2H 2 

### O + CO 2 

### + 2N 2



### 2NH 3 

### + 2NO + 1⁄2O 2 

### → 2N 2 

### + 3H 2 

### O

Flue gas temperature at the point of reactant injection can greatly affect NOx removal efficiencies and the

quantity of NH 3 

### or urea that will pass through the furnace unreacted (referred to as NH 3 

### 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 reducti on reactions diminish and unreacted NH 3 

### emissions increase.

Above the desired temperature range, NH 3 

### is oxidized to NOx resulting in low NOx reduction

efficiencies.

Mixing of the reactant and flue gas within the reac tion zone is also an important factor to SNCR

performance. In large boilers, the physical distance ov er which reagent must be dispersed increases, and

the surface area/volume ratio of the convective pass d ecreases. 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.

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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 ve ndor 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 w ith 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 a nd 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 woul d 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 N 2 

### and water. The overall SCR reactions are:

4NH 3 

### + 4NO + O 2 

### → 4N 2 

### + 6H 2 

### O

8NH 3 

### + 4NO 2 

### + 2O 2 

### → 6N 2 

### + 12H 2 

### O

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 mi nimize ammonium sulfate formation. Below this

range, ammonium sulfate is formed resulting in catal yst 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 so me 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 appr oximately 90% of NOx emissions on a continuous

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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 emi ssions 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.

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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 7,804,000 1 

### 11,831,000

Neural Network 0.30 0.35 250,000 2 

### 250,000 2



### SNCR 0.24 0.29 9,372,000 9,372,000

SNCR (+ LNB/OFA) 0.13 0.13 16,290,000 1 

### 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. Th e 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 assu ming full load operation, and a capacity factor (C.F.)

of 76%.

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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&M 1



### Costs (2012$) Fixed
O&M
Costs (2012$) Total
O&M
Costs (2012$) Variable
O&M 1



### 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 hi ghly volatile and may exceed the values used in this
report.

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## 3. WHITE BLUFF AUXILIARY BOILER

3.1. FUEL SWITCHING

The White Bluff auxiliary boiler is a B&W, single bur ner boiler, firing No. 2 diesel oil, rated at 140,000

lb/hr of steam. Fuel switching to natural gas or propa ne 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 Blu ff, 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 are as, 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 fi nal emission of 0.11 lb/MMBtu. The baseline NOx

emissions from the White Bluff aux boiler are calcul ated 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 natu ral gas and propane, since

FGR is more effective in controlling thermal NOx rath er 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 simultane ously for greater NOx reduction. A vendor has

proposed that for the White Bluff aux boiler, a co mbination of LNB + OFA + FGR will reduce the NOx

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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 bo iler 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 mu st 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 effectiv e NOx reduction, the planned use of the auxiliary

boiler, and the limited availability of SNCR control sy stems 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 comm on, because of their cyc ling operation, and the use

of fuel oil. SCRs have critical operating temperature ranges, which ar e 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.

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3.4. CAPITAL COST ESTIMATES

Capital costs for the technically feasible control optio ns 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 as suming full load operation and a capacity factor (C.F.)

of 10%.

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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

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## 4. LAKE CATHERINE - UNIT 4

4.1. FUEL SWITCHING

Lake Catherine - Unit 4 already combusts natural g as, 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 st op 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 tradeo ff 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 T echnology & 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 increasi ng 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 in creasing the original “high” burner header pressure (BHP) to increase

fuel flow to the burners (See Appendix D). The incr ease in BHP from 42 to 50 psig at Lake Catherine –

Unit 4 would increase fuel flow by 25% and the bur ners would be operated “fuel rich”, lowering NOx

formation. Using this approach would reduce NOx em issions at a small capital cost. The costs for BOOS

with recovery of full unit capacity were based on ven dor cost information for a previous project adjusted

on a $/kW basis to Lake Catherine – Unit 4 and escal ated to 2012. The cost provided does not include

any modifications to the boiler. A boiler OEM or cons ultant would need to evaluate the existing fuel

piping, superheat and reheat attemperation sprays, tube metal temperatures and burner tilt positions for

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the new operating conditions. The expe cted 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 controll ing 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 recircula ting flue gas to the furnace. This recirculated gas

has lower oxygen content than ambient air usually u sed 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 ava ilable 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 LN B + 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 baselin e of 0.4825 lb/MMBtu to 0.44 lb/MMBtu.

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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 practi cal. 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 uni ts 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-no zzle 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 Cath erine 4 and is considered a feasible technology,

although the residence time in the desired temperat ure zone is lower for a gas-fired unit and the

temperature window moves as unit load changes. Th e 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 pr oviding 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 SL-011439 Final Report Rev. 4
5/16/2013 Page No. 18

SCR is a feasible technology for Lake Catherine - Un it 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 inst alled, 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 optio ns 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 ma ximum 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
5/16/2013 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 assumi ng full load operation, and a capacity factor (C.F. of

10%).

Table 4.2: Annual Operating and Maintenance Cost s, Lake Catherine Unit 4 (Based on C.F. of 10%)

Technology Variable
O&M 1,2



### 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 va lues 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 ESTIMA TE SUMMARY SHEETSClient:  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 Burn ers, 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 Cather ine Unit 4 and White Bluff Station Units 1&2. Type of estimates – Conceptual Cost Estimate for the S CR Case and Order of Magnitude Cost Estimates for all
other cases. Project location – White Bluff: Clo se 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 capita l 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 de tails, 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 Fir ed Air cases were based on a previous estimate prepared in 2011. Equipment costs were escalated to current pric ing 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 fr om another cost estimate for a gas fired power station. White Bluff’s auxiliary boiler cost es timate 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 us ing 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 case s, the costs for bulk materials and equipment were derived from recent vendor or manufacturer’s quote for similar items on other projects. W here actual or specific information regarding equipment specifications was availa ble, 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 availabl e from project estimates of similar type and size.

Page 1 of 3Client:  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 dr awing. 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 es timate - 2012 Union rates for Pine Blu ff, Arkansas. Base craft rates are as published in RS Means Labor Rates for the Constructi on Industry, 2012 Edition. The craft rates are then incorporated into work crews appropriate for the activiti es by adding allowances for small tools, construction equipment, insurance, and site overheads to arrive at cr ew rates detailed in the cost estimate. A 1.15 regional labor productivity multiplier is included based on t he 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 & Constr uction 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 determi ned indirectly by taking a percentage of the directly
determined costs and are identified as “Variable Accoun ts”. 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 3Client:  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 pr oject’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 ra nge 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 informa tion 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 le ad 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 tra cks 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 bas ed on good engineering practice. Actual design and quantities may be significantly different t han the quantities shown in the estimates.ESTIMATE NO.: 31813A2 ENTERGY - LA KE CA THERINE

PROJECT NO.: 13027-001 LOW NOX BURNERS AND OVERFIRE AIR SYSTEMS - UNIT 4

ISSUE DATE: CONCEPTUA L ESTIMA TE

PREP./REV.: ADH/

APPROVED:

Estimate Totals

Description Am ount 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 W orking 5-10 Hour Days 41,000

91-3 OT W orking 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 - ConfidentialESTIMATE NO.: 31814AENTERGY - LAKE CATHERINEPROJECT NO.: 13027-001SCR SYSTEM - UNIT 4ISSUE DATE: 8/31/2012CONCEPTUAL ESTIMATEPREP./REV.: ADH/APPROVED: MNOEstimate TotalsDescriptionAmountTotalsLabor19,780,000Material15,815,652Subcontract2,590,000EquipmentOther8,290,00046,475,65246,475,652USD91-1 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 Profit46,475,652USD93-1 EP&P Services3,718,10093-2 CM Support1,394,30093-3 Start-Up/Commissioning464,80093-4 Start-Up/Spare Parts93-5 Excess Liability Insur.93-6 Sales Tax On Indirects93-7 Owners Cost93-8 EPC Fee5,577,20052,052,852USD94-1 Contingency on Equipment94-2 Contingency on Engr Equip94-3 Contingency on Material2,372,40094-4 Contingency on Labor2,967,00094-5 Contingency on Sub.388,50094-6 Contingency on Equipment1,243,50094-7 Contingency on Indirect836,6007,808,00059,860,852USD96-1 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 Indirect59,860,852USD98 - Interest During Constr59,860,852USDTotal59,860,852USDPRINT DATE 9/19/2012 10:49 AMPage 3\\sltimberline\estimating\PROJECTS\ENTERGY\Lake Catherine - ConfidentialESTIMATE NO.: 31815A ENTERGY - LA KE CA THERINE

PROJECT NO.: 13027-001 SNCR SYSTEM - UNIT 4

ISSUE DATE: 9/7/2012 CONCEPTUA L ESTIMA TE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Am ount 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 W orking 5-10 Hour Days 311,700

91-3 OT W orking 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 Serv ices 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 - ConfidentialESTIMATE NO.: 31816A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 LOW NOX BURNERS A ND OVERFIRE A IR SYSTEMS - UNIT 1

ISSUE DATE: 8/31/2012 CONCEPTUA L ESTIMA TE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Am ount 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 W orking 5-10 Hour Days 77,000

91-3 OT W orking 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 Serv ices 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\W hite Bluff - ConfidentialESTIMATE NO.: 31819A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 SNCR SYSTEM - UNIT 1

ISSUE DATE: 9/7/2012 CONCEPTUA L ESTIMA TE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Am ount 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 W orking 5-10 Hour Days 267,300

91-3 OT W orking 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 Serv ices 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\W hite Bluff - ConfidentialESTIMATE NO.: 31817A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 SCR - UNIT 1

ISSUE DATE: 8/31/2012 CONCEPTUA L ESTIMA TE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Am ount 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 W orking 5-10 Hour Days 6,730,000

91-3 OT W orking 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 Serv ices 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\W hite Bluff - ConfidentialESTIMATE NO.: 31832A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 LOW NOX BURNERS A ND OVERFIRE A IR SYSTEMS - UNIT 2

ISSUE DATE: 8/31/2012 CONCEPTUA L ESTIMA TE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Am ount 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 W orking 5-10 Hour Days 77,000

91-3 OT W orking 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 Serv ices 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\W hite Bluff - ConfidentialESTIMATE NO.: 31840A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 SNCR SYSTEM - UNIT 2

ISSUE DATE: 9/7/2012 CONCEPTUA L ESTIMA TE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Am ount 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 W orking 5-10 Hour Days 267,300

91-3 OT W orking 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 Serv ices 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\W hite Bluff - ConfidentialESTIMATE NO.: 31818A ENTERGY - WHITE BLUFF

PROJECT NO.: 13027-001 SCR - UNIT 2

ISSUE DATE: CONCEPTUA L ESTIMA TE

PREP./REV.: ADH/

APPROVED: MNO

Estimate Totals

Description Am ount 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 W orking 5-10 Hour Days 5,759,000

91-3 OT W orking 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 Serv ices 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\W hite 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 IDActivity NameOrg Dur(months)Entergy - NOx Strategy Study - Aux Boiler (LNB/OFA/FGR)...15mPermitting12mA1000Project Authorization0mA1010Air Permit - Prepare/Review/Approve12mEngineering8mA1020Engineering8mProcurement of Major Equipment6mA1030LNB/OFA Spec - Prep/Bid/Eval/Award3mA1070GWC Spec - Prep/Bid/Eval/Award3mVendor Engineering/Fab/Delivery5mA1040LNB/OFA Vendor Engineering/Fabrication/Delivery5mInstallation1mA1050Installation1mCommissioning & Start-Up2mA1060Commissioning & Start-Up2m1234567891011121314151617MonthRun Date: 09-17-12NOx Control Technology Cost and Performance Study forEntergy Services, Inc. White Bluff and Lake CatherineAux Boiler Low NOx Burner/Over-Fire Air/Flue Gas Recirculation (LNB/OFA/FGR)....Activity IDActivity NameOrg Dur(months)Entergy - NOx Strategy Study - Neural Network24mPermitting8mA1000Project Authorization0mA1010Air Permit - Prepare/Review/Approve8mEngineering3mA1020Engineering3mProcurement of Major Equipment3mA1030Neural Network Spec - Prep/Bid/Eval/Award3mVendor Engineering/Fab/Delivery6mA1040NN Vendor Engineering/Fabrication/Delivery6mInstallation1mA1050Installation1mCommissioning & Start-Up12mA1060Commissioning & Start-Up12m-1123456789101112131415161718192021222324252627MonthRun Date: 09-17-12NOx Control Technology Cost and Performance Study forEntergy Services, Inc. White Bluff and Lake CatherineNeural Network....Activity IDActivity NameOrg Dur(months)Entergy - NOx Strategy Study - Low NOx Burners/OverFire Air (LNB/OFA)...19mPermitting12mA1000Project Authorization0mA1010Air Permit - Prepare/Review/Approve12mEngineering8mA1020Engineering8mProcurement of Major Equipment7mA1030LNB/OFA Spec - Prep/Bid/Eval/Award3mA1070GWC Spec - Prep/Bid/Eval/Award3mVendor Engineering/Fab/Delivery6mA1040LNB/OFA Vendor Engineering/Fabrication/Delivery6mInstallation3mA1050Installation3mCommissioning & Start-Up4mA1060Commissioning & Start-Up4m12345678910111213141516171819202122MonthRun Date: 09-17-12NOx Control Technology Cost and Performance Study forEntergy Services, Inc. White Bluff and Lake CatherineLow NOx Burners/Over-Fire Air (LNB/OFA)....Activity IDActivity NameOrg Dur(months)Entergy - NOx Strategy Study - Induced Flue Gas Recirculation (IFGR)ir...17mPermitting2mA1000Project Authorization0mA1010Air Permit - Prepare/Review/Approve2mEngineering9mA1020BOP Engineering9mProcurement of Major Equipment6mA1140FGR Duct Procurement Spec - Prep/Bid/Eval/Award3mA1030Mech Install Spec - Prep/Bid/Eval/Award3mA1120Elec Install Spec - Prep/Bid/Eval/Award3mVendor Engineering/Fab/Delivery6mA1040FGR Duct Vendor Engineering/Fabrication/Delivery6mInstallation4mA1050Installation4mCommissioning & Start-Up2mA1060Commissioning & Start-Up2m12345678910111213141516171819MonthRun Date: 09-17-12NOx Control Technology Cost and Performance Study forEntergy Services, Inc. White Bluff and Lake CatherineInduced Flue Gas Recirculation (IFGR)....Activity IDActivity NameOrg Dur(months)Entergy - NOx Strategy Study - Flue Gas Recirculation (FGR)on ...22mPermitting8mA1000Project Authorization0mA1010Air Permit - Prepare/Review/Approve8mEngineering10mA1020BOP Engineering10mProcurement of Major Equipment6mA1150FGR Fan Procurement Spec - Prep/Bid/Eval/Award3mA1140FGR Duct Procurement Spec - Prep/Bid/Eval/Award3mA1030Mech Install Spec - Prep/Bid/Eval/Award3mA1120Elec Install Spec - Prep/Bid/Eval/Award3mVendor Engineering/Fab/Delivery10mA1040FGR Duct Vendor Engineering/Fabrication/Delivery6mA1160FGR Fan Vendor Engineering/Fabrication/Delivery10mInstallation5mA1050Installation5mCommissioning & Start-Up2mA1060Commissioning & Start-Up2m123456789101112131415161718192021222324MonthRun Date: 09-17-12NOx Control Technology Cost and Performance Study forEntergy Services, Inc. White Bluff and Lake CatherineFlue Gas Recirculation (FGR)....Activity IDActivity NameOrg Dur(months)Entergy - NOx Strategy Study - Selective Non-Catalytic Reduction (SNCR)tic ...16mPermitting12mA1000Project Authorization0mA1010Air Permit - Prepare/Review/Approve12mEngineering8mA1020BOP Engineering8mProcurement of Major Equipment6mA1030SNCR Spec - Prep/Bid/Eval/Award3mA1070Civil/Structural Installation Spec - Prep/Bid/Eval/Award3mA1080Mech Installation Spec - Prep/Bid/Eval/Award3mA1090Elec/I&C Installation Spec - Prep/Bid/Eval/Award3mVendor Engineering/Fab/Delivery6mA1040SNCR Vendor Engineering/Fabrication/Delivery6mInstallation3mA1050Installation3mCommissioning & Start-Up1mA1060Commissioning & Start-Up1m1234567891011121314151617MonthRun Date: 09-14-12NOx Control Technology Cost and Performance Study forEntergy Services, Inc. White Bluff and Lake CatherineSelective Non-Catalytic Reduction (SNCR)....Activity IDActivity NameOrg Dur(months)Entergy - NOx Strategy Study - Selective CatalyticReduction (SCR)Red...32mPermitting12mA1000Project Authorization0mA1010Air Permit - Prepare/Review/Approve12mEngineering16mA1020BOP Engineering16mProcurement of Major Equipment12mA1140Ammonia Injection System Procurement Spec - Prep/Bid/Eval/Award3mA1150Catalyst Procurement Spec - Prep/Bid/Eval/Award3mA1170Fan Spec - Prep/Bid/Eval/Award3mA1190Ductwork Spec - Prep/Bid/Eval/Award3mA1130Structural Steel Spec - Prep/Bid/Eval/Award3mA1030Mech Install Spec - Prep/Bid/Eval/Award3mA1120Elec Install Spec - Prep/Bid/Eval/Award3mVendor Engineering/Fab/Delivery16mA1160Catalyst Vendor Engineering/Fabrication/Delivery12mA1210Structural Steel Vendor Engineering/Fabrication/Delivery7mA1200Ductwork Vendor Engineering/Fabrication/Delivery10mA1040Ammonia Injection System Vendor Engineering/Fabrication/Delivery16mA1180Fan Vendor Engineering/Fabrication/Delivery12mInstallation18mA1050Installation18mCommissioning & Start-Up2mA1060Commissioning & Start-Up2m12345678910111213141516171819202122232425262728293031323334MonthRun Date: 09-17-12NOx Control Technology Cost and Performance Study forEntergy Services, Inc. White Bluff and Lake CatherineSelective 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 MAINTENAN CE COST ESTIMATESNOx Control Technology Cost and Performance StudyNOXComplianceCostsProject #13027-0015/20/2013Unit NameWhite Bluff 1Unit DataSize (Gross kW) 815,000 Aq.Ammonia $/t $700Average NOx Emission Rate (lb/MMBtu at fullload)0.33An.Ammonia $/t $400Nominal 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/FWater Cost, $/1000 gal(3) 2Boiler Eff. (%)84 Electricity, $/MWh 41.50Estimated NOx, tons/day Max26.936Emission Limit, tons-NOx Sales/Buy rate, $/ton-Fuel -PRBSeasonal Days153Basis 0Analysis - Enter "0" for Annual and 1 for SeasonalCF For Variable O&M 76.00Estimated Reductionfrom BaselineEmission Rate AfterControlTons of NOx Emission,Seasonal/AnnualTons of NOx Removed,season/annual Estimated Capital Cost Fixed O&MVariable O&M,season or yrFuel Impact,season or yrTechnology%(lb/mmBtu) tons tons$/kW $/unit$/yr$/@CF$/@CFLNB + OFA (Note 5) 54.5 0.15 4,469 5,363 9.6 $7,804,000 $142,000 $0 $0Neural Net 10.0 0.30 8,848 983 0.3 $250,000 $50,000 $0 $0Full SNCR 26.5 0.24 7,229 2,602 11.5 $9,372,000 $169,000 $5,377,000 $281,000LNB+OFA+Full SNCR 61.4 0.13 3,799 6,033 20.0 $16,290,000 $311,000 $4,154,000 $384,000LNB+OFA+Full SCR83.3 0.055 1,639 8,193 248.6 $202,601,000 $608,000 $2,836,000 $0(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 CostsOperating & Maintenance CostEntergy - NOX Compliance Cost Worksheet - 051613/White Bluff 1Page 1 of 3NOx Control Technology Cost and Performance StudyNOXComplianceCostsProject #13027-0015/20/2013Unit NameWhite Bluff 2Unit DataSize (Gross kW) 844,000 Aq.Ammonia $/t $700Average NOx Emission Rate (lb/MMBtu at fullload)0.39An.Ammonia $/t $400Nominal 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/FWater Cost, $/1000 gal(3) 2Boiler Eff. (%)84 Electricity, $/MWh 41.50Estimated NOx, tons/day Max31.833Emission Limit, tons-NOx Sales/Buy rate, $/ton-Fuel -PRBSeasonal Days153Basis 0Analysis - Enter "0" for Annual and 1 for SeasonalCF For Variable O&M 76.00Estimated Reductionfrom BaselineEmission Rate AfterControlTons of NOx Emission,Seasonal/AnnualTons of NOx Removed,season/annual Estimated Capital Cost Fixed O&MVariable O&M,season or yrFuel Impact,season or yrTechnology%(lb/mmBtu) tons tons$/kW $/unit$/yr$/@CF$/@CFLNB + OFA 61.5 0.15 4,469 7,150 14.0 $11,831,000 $142,000 $0 $0Neural Net 10.0 0.35 10,457 1,162 0.3 $250,000 $50,000 $0 $0Full SNCR 26.5 0.29 8,544 3,076 11.1 $9,372,000 $169,000 $6,338,000 $333,000LNB+OFA+Full SNCR 67.3 0.13 3,799 7,821 24.1 $20,317,000 $311,000 $4,158,000 $384,000LNB+OFA+Full SCR85.9 0.055 1,639 9,981 211.2 $178,240,000 $608,000 $2,858,000 $0(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.Operating & Maintenance CostReagent CostsEntergy - NOX Compliance Cost Worksheet - 051613/White Bluff 2Page 2 of 3NOx Control Technology Cost and Performance StudyNOXComplianceCostsProject #13027-0015/20/2013Unit nameLake Catherine Unit 4Unit DataSize (Gross kW) 558,000 Aq.Ammonia $/t $700Average NOx Emission Rate (lb/MMBtu) 0.4825 An.Ammonia $/t $4000.271 2011 Top 90% 0.275Nominal Max. Boiler Heat Input (mmBtu/hr) 5,850.0 Urea $/t $3500.166 2010 Top 90% 0.169Avg. Heat Rate (Btu/kwh) 10,483.9 N/F-T Urea $/t $6180.194 2011 Top 90% 0.197Aux. Power (kw) - Gas Cost, $/MBtu 4.9000.210 0.214Est. Capacity Factor (%) 10.00Water Cost, $/1000 gal(3) 2Boiler TypeT/FElectricity, $/MWh41.50Boiler Eff. (%) 82Estimated NOx, tons/day Max 3.387Emission Limit, tons -NOx Sales/Buy rate, $/ton2500.0FuelGasSeasonal Days153Basis 0Analysis - Enter "0" for Annual and 1 for SeasonalCF For Variable O&M 10.00Estimated Reductionfrom BaselineEmission Rate AfterControlTons of NOx Emission,Seasonal/AnnualTons of NOx Removed,season/annual Estimated Capital Cost Fixed O&MVariable O&M,season or yrFuel Impact,season or yrTechnology%(lb/mmBtu) tons tons$/kW $/unit$/yr$/@CF$/@CFBaseline0 0.4825BOOS (at 558 MW) 50.0 0.24 618 618 1.6 $893,000 $21,000 $0 $0LNB + OFA 60.0 0.19 495 742 15.7 $8,762,000 $210,000 $0 $0SCR 90.0 0.05 124 1,113 106.8 $59,587,000 $358,000 $254,000 $0SNCR 40.0 0.29 742 495 27.8 $15,507,000 $279,000 $1,542,000 $98,000Water Injection 9.1 0.44 1,124 113 3.9 $2,177,000 $52,000 $18,000 $468,000IFGR (below 500 MW) 19.0 0.39 1,001 235 3.9 $2,166,000 $52,000 $0 $0FGR 60.0 0.19 495 742 20.6 $11,489,000 $207,000 $142,000 $0LNB/OFA + SNCR 70.0 0.14 371 865 43.5 $24,269,000 $489,000 $393,000 $69,000LNB/OFA + SCR94.00.03741,162122.5$68,349,000$568,000$268,000$0(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 CostsOperating & Maintenance CostEntergy - NOX Compliance Cost Worksheet - 051613/LC4 '03 DataPage 3 of 3

### 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 LOADTo : 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

************************************************************************ This e-mail and any of its attachments may contain ETEC Inc. proprietary information, which is privileged, confidential, or subject to copyright belonging to the ETEC Inc. This e-mail is intended solely for the use of the individual or entity to which it is addressed. If you are not the intended recipient of this e-mail, you are hereby notified that any dissemination, distribution, copying, or action taken in relation to the contents of and attachments to this e-mail is strictly prohibited and may be unlawful. If you have received this e-mail in error, please notify the sender immediately 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 practic al and cost-effective means for achieving staged combustion (i.e., m odifying burner stoichoi metry 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 C ontrolled", 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 termina ting 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 pe ak flame temperatures, and reducing NOx formation. The un-reacted products combine with th e air from the above te rminated-fuel burners to complete burnout before exiting the furnace. I have personally been involved with implementing BOOS operation on virtually every ga s fired electric utility boiler design across the country since the mid 1970's. In almost every cas e, the original "high" burner header pressure (BHP) set point had to be increased to acco mmodate 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 Modi fication (BOOS) NOx Reduction

NM4 4BOOS NM4 Baseline

### Figure 2- Ninemile Units 4 and 5 BOOS Pattern (Top Elevation Out of Serv ice & 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 550BHP,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 600NOx,lb/mmbtu

LOAD, MWG 

### Lake Catherine Unit 4 Predicted NOx with 4BOOS

Baseline

BOOS