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 2001-2003baseline 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 factors 1 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 0.9 110/1/200011/20/20001/9/20012/28/20014/19/20016/8/20017/28/20019/16/200111/5/200112/25/20012/13/20024/4/20025/24/20027/13/20029/1/200210/21/200212/10/20021/29/20033/20/20035/9/20036/28/20038/17/200310/6/200311/25/20031/14/20043/4/2004Capacity 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 2007 2 measured NOx emissions at 0.411 lb/MMBtu at an average heat input of 5,194.5 MMBtu while testing performed in 2012 3 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 Environmentalhigh-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 youproject 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 EPA 4 , “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 percent 5

.

Under the BART Guidelines 6 , 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 391673. 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 orderto 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 islikely 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.