Entergy Response to 

Region 6 Comments on Entergy Lake Catherine BART Report 

06/24/13 

Entergy has reviewed the comments provided by EPA Region 6 on March 29, 2013, and 

appreciates the opportunity to provide the below responses. To simplify the format of this 

document, we have included each of EPA’s comments, followed by our response. Submitted 

concurrently herewith is a revised Five-Factor Analysis (2013 Revised FFA) incorporating 

several revisions as discussed below. 

1. Fuel Oil Firing Scenario

x EPA Comment 1 - The BART report states that “If conditions change such that it 

becomes economic to burn fuel oil, a five factor analysis will be submitted for approval 

in the SIP. The combustion of fuel oil [at Unit 4] would not occur until final SIP 

approval.” ADEQ should ensure that the source’s air permit is revised or that language is 

included in the Arkansas BART rule to capture the condition that Unit 4 will not burn 

fuel oil until BART for all pollutants for the fuel oil firing scenario is approved into the 

SIP. 

Entergy Response – Entergy will accept the inclusion of such a limit within the source’s 

air permit or the BART rule. 

 

2. NOx Baseline Emissions/Controlled Emission Rates

x EPA Comment 2 - In reviewing the draft NOx BART analysis there are a number of 

issues with how the baseline emissions the cost and effectiveness of various control 

technologies are estimated that make it difficult to evaluate whether a reasonable decision 

is being recommended for BART. These issues are outlined below. We would welcome 

the opportunity to discuss further. 

Entergy Response – See below for responses to specific issues. 

x EPA Comment 3 - The baseline annual emission rate that is used to estimate the control 

efficiency of NOx controls and to calculate the annual tons reduced in the cost 

effectiveness calculations is 0.48 lb/MMBtu, based on the 24-hr maximum emission rate 

during the baseline period. However, based on CEMS data from CAMD (see table 

below), it appears that the average annual NOx emission rate from the 2001-2003 
baseline period is 0.18 lb/MMBtu, and the maximum is 0.198 lb/MMBtu. The maximum 

30-day rolling average during the baseline period is 0.377 lb/MMBtu; however, this is 

driven by one unusually high day. The maximum 30-day rolling average that excludes the 

highest day falls below 0.3 lb/MMBtu (see graph below), and the second highest 24-hr 

emission rate during the baseline period is 0.346 lb/MMBtu. Based on this information, 

presented in the table and graph below, it appears that using 0.48 lb/MMBtu as the 

baseline may not be representative of actual emissions from the baseline period and that 

the emission rates achievable by the NOx controls are potentially lower than what was 

evaluated in the BART analysis. Appendix Y to Part 51 provides the following: 

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

annual emissions for the source. In general, for the existing sources subject to 

BART, you will estimate the anticipated annual emissions based upon actual 

emissions from a baseline period” (Appendix Y to Part 51, section IV.D.4.d).” 

ADEQ should ensure that the baseline emission rate that is used is in accordance with 

Appendix Y to Part 51. In addition, a BART evaluation requires that “in analyzing the 

technology you take into account the most stringent emission control level that the 

technology is capable of achieving” (70 FR 39166). ADEQ should ensure that this 

requirement has been met for all NOx controls evaluated. We note that in 2000, we 

approved into the Texas SIP a NOx emission limit of 0.10 lb/MMBtu based on a daily 

average for utility boilers located in the Beaumont/Port Arthur area (65 FR 64148). In the 

supporting documentation included in the SIP submittal, Texas explained that since the 

majority of the boilers affected by that limit were tangentially-fired gas boilers, it was 

expected that the limit would be achievable with combustion modification techniques. 

Lake Catherine Unit 4 is the same type of boiler as this. Please ensure that the controlled 

emission rates evaluated for all NOx controls reflect the most stringent emission level 

achievable by that technology. 

Year Operating 

Time 

Avg. NOx Rate 

(lb/MMBtu) 

NOx 

(tons) 

Heat Input 

(MMBtu) 

Capacity 

factor* 

2001 6987.75 0.1943 1724.201 1.443E+07 28.2% 

2002 5651.25 0.198 1421.07 1.242E+07 24.2% 

2003 3972 0.1465 540.117 5.770E+06 11.3% 

2004 1534.22 0.1238 139.971 1.904E+06 3.7% 

2005 2058.55 0.1339 195.917 2.413E+06 4.7% 

2006 314.05 0.1422 25.58 2.917E+05 0.6% 

2007 415.91 0.4014 89.304 4.121E+05 0.8% 

2008 883.79 0.1751 113.288 1.161E+06 2.3% 

2009 823 0.2666 191.427 1.416E+06 2.8% 
2010 1488.69 0.1428 150.545 1.800E+06 3.5% 

2011 1303.19 0.1471 145.149 1.499E+06 2.9% 

2012 4312.99 0.1881 927.544 7.346E+06 14.3% 

* Calculated as: annual heat input / (5850 MMBtu/hr *8760 hr/yr) 

Entergy Response – The existing NOx emission rate for Lake Catherine Unit 4 varies 

over a wide range and is highly dependent on the operating load of the unit. With 

relatively low NOx emission rates (lb/MMBtu) at low loads and relatively high NOx 

emission rates at high loads. The NOx emission rate variability correlates closely with 

operating load in a manner that is readily apparent in comparing the emission rate plot 

produced by EPA (above) with a similar plot of capacity factors over the same period 

(below). The figure below represents 24-hour (red) and 30-day rolling (blue) average 

capacity factors1 for Lake Catherine Unit 4 over the same time period (2001-2003) as 

presented by EPA. 

 

1

 Capacity factor calculated as the actual 24-hour or 30-day rolling heat input divided by the maximum potential 24-

hour or 30-day heat input based on the rated heat input capacity of 5,850 MMBtu/hr. Only unit operating days were 

considered in calculating the 30-day rolling average values. 
Lake Catherine U4 Capacity Factor

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

10/1/2000

11/20/2000

1/9/2001

2/28/20014/19/2001

6/8/2001

7/28/20019/16/200111/5/2001

12/25/2001

2/13/2002

4/4/2002

5/24/20027/13/2002

9/1/2002

10/21/200212/10/2002

1/29/20033/20/2003

5/9/2003

6/28/20038/17/200310/6/2003

11/25/2003

1/14/2004

3/4/2004

Capacity Factor

The day singled out by EPA as “unusually high” (Nov. 12, 2003) represents a day with a 

high daily capacity factor, which correlates to a higher NOx emission rate on a 

lb/MMBtu basis. Emissions from this unit have been consistently measured in the range 

of 0.5 lb/MMBtu near full-load operation. Stack testing performed in 20072 measured 

NOx emissions at 0.411 lb/MMBtu at an average heat input of 5,194.5 MMBtu while 

testing performed in 20123 measured NOx emissions at 0.528 MMBtu/hr at an average 

heat input of 5,192.3 MMBtu/hr. 

This unit has historically been operated as an intermediate or peak load unit. As such, the 

typical daily capacity factor for the unit varies over the entire operating range (0-100%) 

in a manner that significantly differs from a base-load unit which would typically operate 

at a daily average capacity factor between 70-100%. Entergy must be able to utilize this 

unit across its full capacity range. Consequently, the baseline Entergy selected, which 

reflects the full range of capacity factors, is appropriate for this unit. 

It is important to note that the same utilization and emissions data were utilized for the 

visibility modeling. Were Entergy to select a period with lower utilization, and lower 

emission rates, it would be necessary to remodel the unit, also utilizing lower capacity 

factors, lower emission rates, lower exit velocities, etc. However, it is not clear that a 

lower BART emission rate would be appropriate. Unit 4 must, nonetheless, preserve its 

 

2

 Testing conducted on September 8, 2007 by Metco Environmental 

3

 Testing conducted on September 11, 2012 by Metco Environmental 
high-daily-capacity-factor optionality. Further, if Entergy were to use lower baseline 

emissions for the model, the incremental visibility benefits of each technology would be 

smaller and the cost-effectiveness of each technology would be worse at each level. 

 

Finally, Entergy utilized this same baseline approach in the original 2006 FFA for Unit 4. 

Neither ADEQ nor EPA commented on or objected to this approach. Please note, also, 

that the annual NOx mass emission value (1,236 tpy) utilized within the 2013 FFA is 

approximately equal to the average of the annual mass emissions during the 2001-2003 

baseline period (1,228.46 tpy). 

x EPA Comment 4 - The NOx removal efficiency of BOOS assumed in the BART analysis 

is based on an estimate from Entropy Technology and Environmental Consultants, while 

the removal efficiencies of FGR, LNB/SOFA, SCR, and SNCR are based on estimates 

from Sargent & Lundy. Please provide documentation of these estimates. 

Entergy Response – A copy of the revised Sargent and Lundy (S&L) NOx study report is 

included as Appendix D to the revised BART Five Factor Analysis for Lake Catherine, 

Unit 4 (2013 Revised FFA). This study was revised in May 2013 to incorporate 

additional information which was not available at the time of the original study. This 

report includes (Appendix D) information from ETEC regarding the expected 

performance of BOOS. 

x EPA Comment 5 - Entergy assumes an historical 10 percent capacity factor in 

determining BART. EPA agrees that Unit 4 historically operated at less than a 10 percent 

capacity factor during the 2004-2011 period. However, the unit’s capacity factor for the 

2001-2003 baseline period should be used for the BART analysis. Based on our 

calculations, the average annual capacity factor during 2001-2003 was 21.2% (see table 

above). Otherwise, a 10 percent capacity factor may be assumed in the BART analysis as 

long as this is made into an enforceable limit. This is important because in the cost 

effectiveness calculations, Entergy estimates the annual tons removed from baseline 

annual emissions that are calculated by multiplying the baseline emission rate by an 

annual heat input that reflects Unit 4’s capacity factor. Therefore, using a 10 percent 

capacity factor underestimates the annual tons reduced for all the control scenarios. As 

such, the NOx controls evaluated are potentially more cost effective than estimated by 

Entergy. As Appendix Y to Part 51 states: 

 “The baseline emissions rate should represent a realistic depiction of 

anticipated annual emissions for the source. In general, for the existing 

sources subject to BART, you will estimate the anticipated annual 

emissions based upon actual emissions from a baseline period. When you 
project that future operating parameters (e.g., limited hours of operation or 

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

will differ from past practice, and if this projection has a deciding effect in 

the BART determination, then you must make these parameters or 

assumptions into enforceable limitations. In the absence of enforceable 

limitations, you calculate baseline emissions based upon continuation of 

past practice” (Appendix Y to Part 51, section IV.D.4.d). 

Entergy Response –As outlined in the BART Guidelines published by EPA4

, “the 

baseline emissions rate should represent a realistic depiction of anticipated annual 

emissions from the source...”. As noted by EPA, annual capacity factors for Unit 4 have 

been less than 10 percent for the 2004-2011 period. Entergy anticipates that future 

annual capacity factors for this unit will be consistent with those observed from 2004-

2011. The annual capacity factor for 2012 increased due to anomalous grid reliability 

issues which are not anticipated to occur in the future. To provide for a conservative 

estimate of anticipated annual emissions from the source, Entergy paired a conservative 

estimate of the annual capacity factor (10 percent) with the maximum daily average 

emission rate (0.4825 lb/MMBtu) to calculate the baseline NOx emission rate of 1,236 

tpy. This rate significantly exceeds the observed annual average emissions for the 2004-

2011 years which are anticipated to be most representative of future emissions from this 

unit. This approach likely over-estimates the annual tons reduced for each control 

scenario, contrary to EPA’s contention. 

In a March 2012 Federal Register notice in which EPA partially approved and partially 

disapproved the initial Regional Haze SIP submittal from the state of Arkansas, EPA 

agreed that Unit 4 has historically operated at a capacity factor of less than 10 percent5. 

Under the BART Guidelines6, an enforceable limit on a unit’s capacity factor is only 

required when future operating parameters, such as capacity factor, “will differ from past 

practice...”. As Entergy is projecting that future utilization of Unit 4 will be consistent 

with past practice, no such limit is necessary as a result of the BART determination. If 

future capacity factors change, ADEQ and EPA may impose further NOx emission 

reductions on Unit 4, if necessary, in later planning periods to show reasonable progress. 

 

4

 70 FR 39167 

5

 77 FR 14641 

6

 70 FR 39167 
3. NOx Cost Evaluation

x EPA Comment 6 - For the cost estimate for the BOOS control option, please explain why 

the first year O&M costs are considerably higher than for subsequent years ($871,000 vs. 

$21,000). 

Entergy Response – It is anticipated that BOOS can be implemented on the unit without 

any capital expenditures. The one-time costs associated with BOOS implementation 

would instead be incorporated into the facility’s O&M budget for the fiscal year. In order 

to provide an apples-to-apples comparison with the other NOx control options, these onetime additional O&M costs were treated as if the cost were a capital expenditure. 

Entergy notes that in the revised S&L NOx study, the estimate of this one-time O&M 

cost to implement BOOS was revised to $893,000. 

x EPA Comment 7 - The estimates for the capital costs for LNB/SOFA, 

LNB/SOFA+SNCR, and LNB/SOFA+SCR; the first-year O&M costs for BOOS; the 

fixed O&M costs for all NOx control options; and the variable O&M costs for BOOS, 

SNCR (alone), and SCR (alone) are based on the “NOx Control Technology Cost and 

Performance Study” provided by Sargent & Lundy. Please provide a copy of this 

document. 

Entergy Response - A copy of the revised S&L NOx study report is included as 

Appendix D to the 2013 Revised FFA. 

x EPA Comment 8 - The estimates for the variable O&M costs for LNB/OFA are based on 

an equation documented in the 2005 Eastern Research Group report “Analysis of 

Combustion Controls for Reducing NOx Emissions from Coal-fired EGUs in the WRAP 

Region.” As this report was based on coal fired EGU data, ADEQ should demonstrate 

that the data and costing methods used are appropriate and applicable to Lake Catherine 

Unit 4, which does not combust coal. 

Entergy Response –The ERG cost method for LNBs developed for coal-fired EGUs was 

utilized for Unit 4 at Lake Catherine since the number of EGUs of similar size and fuel 

type to Unit 4 are small and cost estimates are not as established. Table 1 of the EPA 

Region VII document, "NOx Controls for Existing Utility Boilers" by Bill Neuffer, 

ESD/QAQPS, summarizes that LNBs on PC Wall-fired boilers result in a NOx cost 

effectiveness of $160-$450/ton while LNBs on Oil/Gas Wall-fired boilers result in a NOx 

cost effectiveness of $750-$1700/ton. Therefore, Entergy asserts that the ERG cost 

estimate, while not directly applicable to oil/gas boilers, provides an estimate that is 
likely more cost effective than would be determined if an oil/gas cost method were 

available. 

x EPA Comment 9 - The BART evaluation assumes a 15 year actual service life for all 

NOx control options. Footnote 1 under the BOOS cost estimate in Attachment A states 

that implementation of BOOS would not require capital additions. Since it appears that 

BOOS would not require the installation of additional equipment, please explain why a 

15 year actual service life was assumed in the cost evaluation. We believe that an 

anticipated 30 year equipment life is more appropriate to use in the cost analysis for all 

the NOx control options. Unless proper documentation is provided to demonstrate that 

the anticipated equipment life is limited to 15 years, ADEQ should ensure that the cost 

analysis assumes a 30 year equipment life for all BART determinations. 

Entergy Response – All costs have been re-calculated based on a 30-year equipment life. 

Updated cost information is provided in the June 2013 Revised FFA. In addition to the 

use of a 30-year equipment life, the attached cost estimates contain corrected values for 

the projected variable O&M costs associated with SNCR and SCR controls. The values 

included in the submitted FFA were based on an erroneous estimate that utilized a 100% 

annual capacity factor. At no time during the preparation of the 2013 FFA was a 100% 

annual capacity factor contemplated by Entergy. This error was not identified prior to 

submission of the FFA report, but has been corrected at this time. 

x EPA Comment 10 - The cost evaluations of all NOx control scenarios, with the exception 

of BOOS, includes AFUDC costs. AFUDC costs are not allowed under the EPA Control 

Cost Manual (CCM), and therefore should not be included in the cost evaluation. 

Entergy Response - Entergy disagrees with EPA that AFUDC should not be included as 

part of the costs of control technology. The CCM does not preclude inclusion of AFUDC 

and, indeed, the formula included in the CCM expressly includes AFUDC as a variable. 

The fact that the example used in the CCM “assumes” that AFUDC is zero does not 

reflect a reasoned decision to exclude AFUDC. The CCM expressly anticipates the 

inclusion of AFUDC where appropriate. Further, the CCM clearly allows the inclusion 

of interest costs associated with the control technology. AFUDC is nothing more that the 

interest expense on the investment in the technology that is incurred during construction, 

before the equipment is placed in service. For pollution control technologies being 

considered for Unit 4, the interest expense incurred during the –12-24 months of 

construction can be significant. AFUDC simply includes the interest as part of the capital 

cost, which is standard accounting and rate-making treatment of such costs. Since the 

projected BOOS implementation costs would not be capitalized, no AFUDC would be 

associated with this control option.