Summary of Additional Modeling for Entergy Independence

Prepared by:

Michael Feldman

EPA Region 6

April 20, 2015
Table of Contents

Background .................................................................................................................................................3

Modeling Protocol.......................................................................................................................................4

Additional Modeling Results......................................................................................................................5

Visibility Modeling of SO2 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 CALPUFF 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 were used are available in the docket for our 

proposed action2: 

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 Federal 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 nitrate 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 

IMPROVE equation.

All additional modeling was conducted following the same modeling protocol utilized in the 

previous modeling for the Independence facility. Appendix C to the Technical Support 

Document3 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 facilitywide basis for each control scenario, as outlined below4

.

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 controlled 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/SOFA 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 are 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 TSD 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 Results

Visibility Modeling of SO2 Control Scenarios

Table 2 presents the maximum value of the 98th percentile of the daily maximum impact for the 

three modeled years (2001-2003) for the facility for the baseline and SO2 control scenarios. SO2

controls provide for improvements 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 98th 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 SO2

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

Table 2. Entergy Independence: EPA Modeled Maximum 98th Percentile Visibility 

Impacts (∆dv) of SO2 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 98th 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 24-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. We note that had we modeled a more 

recent baseline for SO2 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 98th Percentile Visibility 

Impacts (∆dv) of SO2 Controls (Facility-wide) with BASE2

Class I Area Distance 

(km)

Visibility Impact Visibility Improvement 

BASE2 Over Baseline 5 Dry FGD6

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 98th 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 emission 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 emissions 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 98th 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 BASE27 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 98th 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 SO2 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 SO2 emissions, the 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 compared to BASE2, compared 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 emissions 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 98th Percentile Visibility 

Impacts (∆dv) of NOx and SO2 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 BASE28 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

HerculesGlades 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 modeling 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 total 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 98th percentile visibility impacts to be more driven by 

sulfate impacts. Therefore, benefits from reductions in NOx emissions on the 98th percentile days 

are slightly reduced. 

Previous modeling of the control scenario including both LNB/SOFA and DFGD showed 

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 benefit 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 

2001 2002 2003 maximum

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 

2001 2002 2003 maximum

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 

2001 2002 2003 maximum

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 

2001 2002 2003 maximum

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 

2001 2002 2003 maximum

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 

2001 2002 2003 maximum

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 

2001 2002 2003 maximum

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