## Summary of Additional Modeling for Entergy Independence

Prepared by:

Michael Feldman

EPA R e gion 6

April 20, 2015

### Table of Contents

Background

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

Modeling Protocol

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

Additional M odeling Results

................................ ................................ ................................ ...................... 5

Visibility Modeling of SO 2 Control Scenarios

................................ ................................ .......................... 5

Visibility Modeling of NOx Control Scenarios

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

Visibility Modeling of NOx and SO2 Control Scenarios

................................ ................................ .......... 7

Comparison of Previous and Additional Visibility Modeling

................................ ................................ ... 8

Attachment A. Entergy Independence Additional Visibility Modeling CALPUFF files

................... 10

Attachment B. Entergy Independence Additional Visibility Modeling Results

................................ . 11

## Background

On April 14, 2015, EPA received a letter from Baker Botts L.L.P. on behalf of Entergy Arkansas
Inc. identifying an error in the modeled location of the Entergy Independence facility. 1 

### We
confirmed that an error was made when the latitude and longitude for the facility were input into
a spreadsheet to convert decimal degree coordinates into the Lambert Conformal Conic (LCC)
coordinates required for the CA LPUFF modeling. 34 degrees latitude was input instead of the
correct value of 35 degrees latitude. This caused the modeled facility location to be
approximately 110km further south than the correct location. The table below shows the

location that was used in the previous CALPUFF modeling and the revised value. Additional
modeling was completed using the corrected facility location. That modeling is described here.

Three versions of the conversion spreadsheet that w ere used are available in the do cket for our
proposed action 2 

### :

1) The original
2) The spreadsheet that was previously relied upon for the Independence facility location
3) The revised spreadsheet that corrects the error identified above

Table 1. Location of Entergy Independence

Latitude Longitude LCC X

- coordinate (km) LCC Y

- coordinate

(km) previous location 34.6733

- 91.4083 510.8348

- 572.7073

revised location 35.6733

- 91.4083 504.0342

- 462.3251

1 April 13, 2015 letter from Mr. Bill Bumpers to Mr. Guy Donaldson, Chief, Air Planning Section, EPA Region 6, RE:
Request for an Extension of the Public Comment Period on the Proposed Rule to Promulgate a Regional Haze and
Interstate Visibility Transport F ederal Implementation Plan for Arkansas, Docket No. EPA

- R06

- OAR

- 2015

- 0189

2 See “AR020.0140

- 00 Additional documents

- Lambert Conformal Conversion workbooks and location correction”
available in the docket to this proposed rulemaking

## Modeling Protocol

As with the previous modeling, we utilized the CALMET v5.53a output generating by Trinity
Consultants and the current regulatory version of CALPUFF (v5.8.4). In POSTUTIL the
MNITRATE =1 setting was used to repartition the total nitrate to reflect the competition between

sulfate and nitr ate for available ammonia and in a step referred to as ―Nitrate Repartitioning

. CALPOST was then used to calculate visibility using the modeled concentrations and the revised

IMPR OVE equation

.

All addition al modeling was conducted following the same modeling protocol utilized in the
previous modeling for the Independence facility. Appendix C to the Technical Support

Document 3 

### describes the modeling protocol, model inputs and emission rates modeled. The only
change made was to change the location of the facility. Modeling was performed on a facility

wide basis for each control scenario, as outlined below 4



### .

Control Scenarios:

1. Baseline (BASE)

– Emission rates for NOx and SO2 are from maximum actual 24

- hr emissions during the 2001

- 2003 period.

2. Dry Scrubber (DFGD)

- Emission rates for NOx are maximum actual 24

- hr
emissions during the 2001

- 2003 period. SO2 emissions are co ntrolled to 0.06

lb/mmBTU.

3. Wet Scrubber (WFGD)

– Emission rates for NOx are maximum actual 24

- hr
emissions during the 2001

- 2003 period. SO2 emissions are controlled to 0.04

lb/mmBTU.

4. Baseline 2 (BASE2)

– Emission rates for SO2 are maximum actual 24

- hr emissions
during the 2001

- 2003 period. Emission rates for NOx are maximum actual 24

- hr
emissions during the 20011

- 2013 period.

5. LNB/SOFA (LNB)

– Emission rates for NOx are at the LNB/S OFA controlled

value of 0.15 lb/mmBTU. Emission rates for SO2 are maximum actual 24

- hr
emissions during the 2001

- 2003 period.

6. LNB/SOFA and DFGD (LNB_DFGD)

- Emission rates for NOx are at the

LNB/SOFA controlled value of 0.15 lb/mmBTU. SO2 emissions ar e controlled to

0.06 lb/mmBTU.

7. Dry Scrubber and Baseline 2 (BASE2_DFGD)

- Emission rates for NOx are

maximum actual 24

- hr emissions during the 2011

- 2013 period. SO2 emissions are

controlled to 0.06 lb/mmBTU

3 See “ AR020.0002

- 00 T SD for EPA's Proposed Action on the AR RH FIP ” available in the docket to this proposed
rulemaking

4 Emission inputs for each scenario are included in Attachment A to Appendix C of the TSD

.

## Additional Modeling R esults

Visibility Modeling of SO 2 

### Control Scenarios

Table 2 presents the maximum value of the 98 th 

### percentile of the daily maximum impact for the three modeled years (2001

- 2003) for the facility for the baseline and SO 2 

### control scenarios. SO 2 

### controls provide for improvem ents in visibility, lowering the impact the facility has on any single Class I area by 1.05 to 1.18 dv. There is little difference between the results of the WFGD and

DFGD in the 98 th 

### percentile values. At the low sulfur emission levels of these controls, nitrates are responsible for the majority of visibility impairment so little benefit is seen in decreasing SO 2 

### emissions from the DFGD rate of 0.06 to the WFGD rate of 0.04 lb/mmBTU.

Table 2. Entergy Independence: EPA Modeled Maximum 98 th 

### Percentile Visibility

Impacts (∆dv) 

### of SO 2 

### Controls (Facility

- wide)

Class I Area Distance

(km) Visibility Impact Visibility Improvement

Over Baseline Incremental

Visibility Improvement

of Wet FGD vs. Dry FGD BASE Dry

FGD Wet

FGD Dry

FGD Wet

FGD

Caney Creek 277 2.512 1.416 1.399 1.096 1.113 0.017

Upper Buffalo 180 2.264 1.086 1.068 1.178 1.196 0.018

Hercules

- Glades 173 1.868 0.812 0.797 1.056 1.071 0.015

Mingo 174 1.859 0.814 0.795 1.045 1.064 0.019

Total

- 8.503 4.128 4.059 4.375 4.444 0.069



### Table 3 presents the maximum value of the 98 th 

### percentile of the daily impact for the three
modeled years for the baseline and DFGD control scenarios utilizing more recent emissions data

for the NOx emissions (BASE2). These results utilize the maximum 2 4

- hr NOx emissions from

the 2011

- 2013 period, which are lower than emission rates from the 2001

- 2003 baseline.
Modeled visibility benefits from the use of DFGD are similar to those modeled with the 2001

- 2003 baseline NOx emissions values shown in Table 2

. W e note that had we modeled a more

recent baseline for SO 2 

### emissions, the baseline visibility impact would be greater and the

visibility benefits modeled from the control scenarios would be greater.

### Table 3. Entergy Independence: EPA Modeled Maximum 98 th 

### Percentile Visibility Impacts (∆dv) 

### of SO 2 

### Controls (Facility

- wide) with BASE2

Class I Area Distance (km) Visibility Impact Visibility Improvement

Over Baseline BASE2 5 Dry FGD 6

Caney Creek 277 2.028 1.045 0.983

Upper Buffalo 180 2.003 0.819 1.184

Hercules

- Glades 173 1.734 0.595 1.139

Mingo 174 1.761 0.608 1.153

Total

- 7.526 3.067 4.459



### Visibility Modeling of NOx Control Scenarios

Table 4 presents the maximum value of the 98 th 

### percentile of the daily maximum impact for the three modeled years (2001

- 2003) for the facility for the baseline and NOx control scenarios. The

baseline results utilize the maximum 24

- hr NOx emissions from the 2011

- 2013 period, which are

lower than emiss ion rates from the 2001

- 2003 baseline. LNB/SOFA provides for improvements in visibility on any single Class I area ranging from 0.15 to 0.46 dv.

5 Baseline NOx emissions were updated to the maximum 24

- hr emissio ns from 2011

- 2013 for the evaluation of the
anticipated benefit from NOx controls.

6 Baseline NOx emissions were updated to the maximum 24

- hr emissions from 2011

- 2013 for the evaluation of the
anticipated benefit from NOx controls.

### Table 4 . Entergy Independence: EPA Modeled Maximum 98 th 

### Percentile Visibility Impacts (∆dv) 

### of NOx Controls (Facility

- wide) with BASE2

Class I Area Distance (km) Visibility Impact Visibility Improvement

of LNB/SOFA Over

Baseline BASE2 7 LNB/SOFA

Caney Creek 277 2.028 1.569 0.459

Upper Buffalo 180 2.003 1.805 0.198

Hercules

- Glades 173 1.734 1.561 0.173

Mingo 174 1.761 1.613 0.148

Total

- 7.526 6.548 0.978



### Visibility Modeling of NOx and SO2 Control Scenarios

Table 5 presents the maximum value of the 98 th 

### percentile of the daily maximum impact for the three modeled years (2001

- 2003) for the facility for the two different baselines modeled and a

control scenario with both LNB/SOFA and DFGD. The “BASE” results utilize the maximum

24

- hr SO 2 

### and NOx emissions from the 2001

- 2003 period.

The “BASE2” results utilize the maximum 24

- hr NOx emissions from the 2011

- 2013 period,

which are lower than emission rates from the 2001

- 2003 baseline. We note that had we modeled

a more recent baseline for SO 2 

### emissions, th e baseline visibility impacts would be greater and the visibility benefits modeled from the control scenarios would also be greater. Modeling of both LNB/SOFA and DFGD shows visibility benefits ranging from 1.40 to 1.52 dv at each Class I area when compar ed to BASE2

, c o m p a r e d to visibility benefits ranging from 1.05 to 1.18 dv for only DFGD when compared to BASE and 0.98 to 1.18 dv for only DFGD when compared to

BASE2.

7 Baseline NOx emis sions were updated to the maximum 24

- hr emissions from 2011

- 2013 for the evaluation of the
anticipated benefit from NOx controls.

### Table 5 . Entergy Independence: EPA Modeled Maximum 98 th 

### Percentile Visibility

Impacts (∆dv) 

### of NOx and SO 2 

### Controls (Facility

- wide) with BASE and BASE2

Class I

Area Distance

(km) Visibility Impact Visibility Improvement

of LNB/SOFA

and DFGD

Over BASE Visibility

Improvement of

LNB/SOFA and

DFGD Over

BASE2 BASE BASE2 8 LNB/SOFA

and DFGD

Caney

Creek 277 2.512 2.028 0.56 1.952 1.468

Upper

Buffalo 180 2.264 2.003 0.482 1.782 1.521

Hercules

Glades 173 1.868 1.734 0.331 1.537 1.403

Mingo 174 1.859 1.761 0.338 1.521 1.423

Total

- 8.503 7.526 1.711 6.792 5.815



### Comparison of Previous and Additional Visibility Modeling

A summary of the previous modeling results is available in Appendix C to the TSD. Visibility modeling results for this additional model ing can be found as Attachment B to this document. As shown in Table 6 below, modeled visibility benefits from SO2 control (dry flue gas desulfurization) are the same or larger in the additional modeling. The largest difference is an increase in modeled visibility benefit from control of 0.29 dv (to a t otal of visibility improvement of 1.178 dv) at Upper Buffalo. The largest modeled benefit from NOx controls is at Caney Creek and is approximately the same in the additional modeling. Modeled visibility benefits from NOx

control at the three other Class I areas are slightly smaller in the additional modeling. The change in location of the modeled facility resulted in different transport patterns from the facility

to the Class I areas and the modeled 98 th 

### percentile visibility impacts to be more driven by sulfate impacts

. Therefore, benefits from reductions in NOx emissions on the 98 th 

### percentile days are slightly reduced.

Previous modeling of the control scenario including both LNB/SOFA and DFGD sho wed visibility benefits ranging from 1.18 to 1.48 dv at each Class I area when compared to BASE2.

The additional modeling shows larger visibility benefits ranging from 1.40 to 1.52 dv at each Class I area for the combination of LNB/SOFA and DFGD compared to BASE2

.

8 Baseline NOx emissions were updated to the maximum 24

- hr emissions from 2011

- 2013 for the evaluation of the
anticipated be nefit from NOx controls.

### Table 6. Summary of Previous and Additional Regional Haze Modeling for the Entergy

Independence Plant.

Class I area Visibility improvement over baseline (BASE) (deciviews) Visibility improvement over baseline (BASE2) 9 (deciviews)

Dry flue gas desulfurization (previous) Dry flue gas

desulfurization ( additional ) Low NOx

burner/Separated

overfire air (previous) Low NOx burner

benefit/Separated

overfire air ( additional )
Caney Creek 0.938 1.096 0.461 0.459 Upper Buffalo 0.888 1.178 0.248 0.198

Hercules

- Glades 1.056 1.056 0.264 0.173 Mingo 0.871 1.045 0.213 0.148

9 Baseline NOx emissions were updated to the maximum 24

- hr emissions from 2011

- 2013 for the evaluation of the
anticipated benefit from NOx controls.

## Attachment A. Entergy Independence Additional Visibility

Modeling CALPUFF files

Due to the file size of the CALPUFF modeling files, they are not available from the electronic
docket. These files are available upon request. Please email your request to: Michael Feldman

(feldman.michael@epa.gov) or call 214

- 665

- 7200

## Attachment B . Entergy Independence Additional Visibility

Modeling Results

BASE

Class I Area 98th Percentile for Each Year 3 year

average 3 year

maximum 2001 2002 2003

Caney Creek 2.512 1.727 2.073 2.104 2.512

Upper Buffalo 1.737 2.148 2.264 2.050 2.264

Hercules

- Glades 1.736 1.864 1.868 1.823 1.868

Mingo 1.859 1.357 1.386 1.534 1.859

Sum 7.844 7.096 7.591 7.510 7.844



### DFGD

Class I Area 98th Percentile for Each Year 3 year

average 3 year

maximum 2001 2002 2003

Caney Creek 1.416 0.858 1.115 1.130 1.416

Upper Buffalo 0.857 1.084 1.086 1.009 1.086

Hercules

- Glades 0.747 0.809 0.812 0.789 0.812

Mingo 0.752 0.662 0.814 0.743 0.814

Sum 3.772 3.413 3.827 3.671 3.827



### WFGD

Class I Area 98th Percentile for Each Year 3 year

average 3 year

maximum 2001 2002 2003

Caney Creek 1.399 0.827 1.086 1.104 1.399

Upper Buffalo 0.832 1.064 1.068 0.988 1.068

Hercules

- Glades 0.724 0.797 0.795 0.772 0.797

Mingo 0.733 0.643 0.795 0.724 0.795

Sum 3.688 3.331 3.744 3.588 3.744



### BASE2

Class I Area 98th Percentile for Each Year 3 year

average 3 year

maximum 2001 2002 2003

Caney Creek 2.028 1.559 1.805 1.797 2.028

Upper Buffalo 1.655 2.003 1.958 1.872 2.003

Hercules

- Glades 1.679 1.634 1.734 1.682 1.734

Mingo 1.761 1.261 1.201 1.408 1.761

Sum 7.123 6.457 6.698 6.759 7.123

### LNB/SOFA

Class I Area 98th Percentile for Each Year 3 year

average 3 year

maximum 2001 2002 2003

Caney Creek 1.569 1.335 1.443 1.449 1.569

Upper Buffalo 1.505 1.805 1.741 1.684 1.805

Hercules

- Glades 1.433 1.421 1.561 1.472 1.561

Mingo 1.613 1.137 1.124 1.291 1.613

Sum 6.120 5.698 5.869 5.896 6.120



### DFGD_BASE2

Class I Area 98th Percentile for Each Year 3 year

average 3 year

maximum 2001 2002 2003

Caney Creek 1.045 0.649 0.823 0.839 1.045

Upper Buffalo 0.653 0.819 0.815 0.762 0.819

Hercules

- Glades 0.552 0.595 0.594 0.580 0.595

Mingo 0.573 0.484 0.608 0.555 0.608

Sum 2.823 2.547 2.840 2.737 2.840



### LNB/SOFA_DFGD

Class I Area 98th Percentile for Each Year 3 year

average 3 year

maximum 2001 2002 2003

Caney Creek 0.560 0.368 0.452 0.460 0.560

Upper Buffalo 0.354 0.482 0.455 0.430 0.482

Hercules

- Glades 0.331 0.329 0.318 0.326 0.331

Mingo 0.326 0.251 0.338 0.305 0.338

Sum 1.571 1.430 1.563 1.521 1.571