EPA Region 6 comments on Entergy White Bluff draft BART Report 

03/06/13 

EPA has reviewed the draft BART analysis for the Entergy White Bluff facility and our comments are 

included. In general, we believe Entergy has provided most of the information to make a reasoned 

determination regarding BART for the facility. Below, however, we point out areas where additional 

documentation would be necessary to fully support the determination and other areas where there are 

discrepancies from the approaches provided for in EPA guidance. 

1. SO2 BART 

 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 demonstrate this requirement has been met. In particular, the BART report for 

Entergy White Bluff states that wet scrubbers can achieve up to 95% control efficiency at Units 1 

and 2. It is also stated that discussions with vendors suggest that although a wet scrubber may be 

able to achieve up to 97% control at units burning higher sulfur coal, this may not be achievable 

for the low sulfur coal typically combusted at Units 1 and 2. The BART report should include 

documentation from the vendor to corroborate this statement. Furthermore, section 5.4 of the 

BART report indicates that semi-dry scrubbers were evaluated at an outlet SO2 emission rate of 

0.06 lb/MMBtu and wet scrubbers at an outlet SO2 emission rate of 0.04 lb/MMBtu. In section 

5.4 it is stated that this represents 95% removal efficiency for the dry scrubber option and 97% 

removal efficiency for the wet scrubber option when applied to the units’ currently allowable 

SO2 emission rate of 1.2 lb/MMBtu. Considering that the 2001-2003 average SO2 emission rate 

is 0.81 lb/MMBtu at Unit 1 and 0.79 lb/MMBtu at Unit 2 (based on information recently 

provided by Entergy), it appears that the actual removal efficiency evaluated for the two control 

options at Units 1 and 2 is less than 95% for dry scrubbers and less than 97% for wet scrubbers. 

Based on the annual SO2 emissions reductions expected to result from each control option (as 

shown in tables 5-7 and 5-8), it appears that dry scrubbers were evaluated at 91.5% removal 

efficiency for Unit 1 and 90.5% for Unit 2 while wet scrubbers were evaluated at 94.3% removal 

efficiency for Unit 1 and 93.7% for Unit 2. ADEQ should ensure that the requirement to evaluate 

the most stringent emission control level the technology is capable of achieving has been 

satisfied. 

 The executive summary (section 1) of the BART report states that Entergy has concluded that 

the installation of a semi-dry scrubber and baghouse is BART for SO2 for both Units 1 and 2. 

However, the SO2 controls evaluated in the BART report are wet scrubbers and semi-dry 

scrubbers, and no mention of a baghouse is made in the body of the BART report. The cost 

evaluation of the dry scrubber option (in Appendix A) contains line items related to the O&M 

costs of the baghouse, but there does not appear to be a line item for the baghouse capital costs. 

Please specify whether the dry scrubbing technology evaluated and selected as BART is NID or 

some configuration of SDA. 
 In the cost evaluation of SO2 controls Entergy assumed a 15 year equipment life for both wet and 

semi-dry scrubbers, based on a misinterpretation of the EPA Control Cost Manual (CCM).1 EPA 

believes that 30 years is the more appropriate equipment life for scrubbers. If Entergy believes 

that the remaining useful life of the boilers affects the BART determination, then an equipment 

life less than 30 years may be assumed, but this would require a federally enforceable restriction 

preventing further operation of the boilers by a date certain. Scrubber vendors indicate that the 

lifetime of a scrubber is equal to the lifetime of the boiler, which in some cases easily exceeds 60 

years. The typical life for a scrubber is reported as 30 years in published papers and standard cost 

estimating handbooks. Since the capital costs are annualized over a period of time equal to the 

anticipated equipment life, and then added to the annual O&M costs to obtain the total 

annualized costs, the two SO2 control options evaluated will be more cost effective than what is 

estimated in Entergy’s cost evaluation if a 30 year operating life is assumed. 

 In section 5.4.1, it is stated that the capital and O&M costs used in Entergy’s cost effectiveness 

calculations for the wet scrubber option are based on vendor estimates for a system designed to 

achieve 97% control (0.06 lb/MMBtu) for an inlet SO2 rate of 2.0 lb/MMBtu, and that the cost 

for a system designed to achieve an emission rate of 0.04 lb/MMBtu for an inlet SO2 rate of 1.2 

lb/MMBtu would be approximately 5-6% higher. It does not appear that Units 1 and 2 have 

historically burned coal containing 1.2 lb/MMBtu SO2. To properly evaluate cost-effectiveness, 

controls should either be designed to burn coal with the same sulfur content as has been 

historically used at the units (2001-2003), or if the controls evaluated are designed to burn coal 

with a higher sulfur content than has been historically used at the units, ADEQ should ensure 

that the baseline is raised to correspond with the sulfur content of the type of coal the scrubber 

has been designed to burn. 

 In section 5.6 the statement is made that EPA previously agreed that SDA technology is BART 

for White Bluff Units 1 and 2. The statement makes reference to a letter dated November 25, 

2009, from Region 6 to ADEQ, in which comments were provided on the draft Title 

V/Prevention of Significant Deterioration (PSD) permit for White Bluff. In that letter, EPA 

agreed that dry scrubber technology is one of the SO2 controls generally accepted as BART. 

Although that statement, offered in another regulatory context, remains true, EPA action on a 

state’s BART determination can only be made via rulemaking after public notice and comment. 

 Entergy is proposing to use a semi-dry scrubber and a baghouse to satisfy SO2 BART at Units 1 

and 2, which will involve replacing the existing ESPs with baghouses. Since this will likely 

result in a higher PM removal efficiency than currently achieved by the existing ESPs, ADEQ 

should re-evaluate the BART limits previously established for Units 1 and 2 and ensure that the 

limits still meet the criteria of being the most stringent limit reasonably available. 

                                                            

1

 EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002; see 

http://www.epa.gov/ttncatc1/dir1/c_allchs.pdf. 
 The cost evaluations for SO2 controls included undocumented costs, line items that should be 

identified/explained, as well as some costs that are not allowed under the CCM. According to 

the CCM, AFUDC costs are not allowed in estimating capital costs for controls. In addition, for 

the semi-dry scrubber cost evaluation, please provide the following: 

o a breakdown of costs for FGD equipment, FGD materials, BOP equipment, and BOP 

materials; 

o please explain which line item(s) account for the capital costs of the bahouse; 

o the estimate should explain the need for the costs under FGD contractor contingency; 

o the estimate should explain what expenses are accounted for under BOP indirect costs, 

miscellaneous contractor labor, Entergy internal costs, and capital suspense. 

For the wet scrubber cost evaluation, please provide a breakdown of total equipment costs, 

purchased equipment cost, and direct annual costs. 

2. NOx BART 

 Although FGR is identified as a technically feasible NOx control option in sections 6.1 and 6.2 

of the BART report, ADEQ should either justify why this control option is subsequently dropped 

from consideration in the remainder of the BART report, or include it in the BART analysis. 

 In Tables 6-7 and 6-8, Entergy indicates that it evaluated LNB/SOFA to achieve 51% control at 

Unit 1 and 58% control at Unit 2. However, based on the annual NOx emissions reductions 

expected to result from LNB/SOFA, it appears that this control scenario was evaluated at a 

removal efficiency of only 42.8% at Unit 1 and 50.4% at Unit 2. Similarly, it appears that the 

removal efficiencies evaluated for the other two NOx control scenarios may be lower than what 

is stated in Tables 6-7 and 6-8. ADEQ should either explain the discrepancy or revise Tables 6-7 

and 6-8 such that the estimated annual emissions reductions match up with the control efficiency 

for each control scenario. ADEQ should ensure that the most stringent emission control level that 

the technology is capable of achieving has been taken into account (70 FR 39166). 

 Please provide a copy of the “2012 S&L NOx Study” referred to in footnotes 36-38. The 

emission rates evaluated for each NOx control scenario and the estimates for capital costs, fixed 

O&M costs, and some of the variable O&M costs for NOx controls were based on this study. 

This documentation should be included in the proposed SIP. 

 As was done in the cost evaluation of SO2 controls, AFUDC costs were included in the cost 

analysis of NOx controls. According to the CCM, AFUDC costs are not allowed in estimating 

capital costs for controls. 
 In the cost evaluation of NOx controls Entergy assumed a 20 year equipment life for SCR and 

SNCR. Unless proper documentation is provided to demonstrate that the anticipated equipment 

life of SCR and SNCR is limited to 20 years, we believe that an anticipated 30 year equipment 

life would be more appropriate to use in the cost analysis. If Entergy believes that the remaining 

useful life of the boilers affects the BART determination, then an equipment life less than 30 

years may be assumed, but this would require a federally enforceable restriction preventing 

further operation of the boilers by a date certain. 

3. Auxiliary Boiler (SN-05) 

 Please provide modeling files for baseline modeling for SN-05 as well as baseline modeling for 

the three subject-to-BART units combined. 

 Please explain how baseline maximum 24-hr emissions for SN-05 were calculated. We note that 

the modeled emissions for SO2 of 5.8 lb/hr differ from the baseline emission rate modeled in the 

SIP of 32.5 lb/hr. 

 Are there any limitations to the hours of operation of this unit? What are the historical hours of 

operation of this unit? ADEQ should explain why the baseline is representative of this unit’s 

history, as discussed in 40 CFR Part 51 Appendix Y (section IV.D.4.d). 

 The White Bluff BART analysis states: “Since baseline visibility modeling showed that there is 

no opportunity for visibility improvement attributable to SN-05, because not a single day greater 

than 0.5 Δdv is associated with SN-05, it is not possible to install control equipment to improve 

visibility. Therefore, no controls is the SO2 BART (NOx BART) determination for SN-05.” This 

is not an appropriate justification for not completing a BART analysis for the unit. The 0.5 dv 

threshold applies only to the determination of whether the facility, considering all BART eligible 

units, is subject to BART.2

 We note that in some cases, states may adopt a more streamlined 

approach to making BART determinations where appropriate. For example, a State need not 

undertake an exhaustive analysis where it is clear that controls would be costly and any 

improvements in visibility resulting from reductions in emissions would be negligible. 

 

                                                            

2

 As explained by the preamble of the RHR: ‘‘Failing to consider less-than-perceptible contributions to visibility impairment 

would ignore the CAA’s intent to have BART requirements apply to sources that contribute to, as well as cause, such 

impairment.’’ 70 FR 39104, at 39129. Given that sources are subject to BART based on a contribution threshold of no greater 

than 0.5 deciviews, it would be inconsistent to automatically rule out additional controls where the improvement in visibility 

may be less than 1.0 deciview or even 0.5 deciviews. A perceptible visibility improvement is not a requirement of the BART 

determination because visibility improvements that are not perceptible may still be determined to be significant. 
4. Emission Estimation and modeling 

 To estimate sulfuric acid emissions to model for the baseline and control cases, all inorganic PM 

was assumed to be SO4. This assumption and assumptions of SO4 reductions due to controls 

impacts the baseline modeling as well as the visibility benefit from WFGD when compared to 

NID. We recommend that sulfuric acid emissions from power plants are calculated by 

estimating the amount of H2SO4 produced and the amount of H2SO4 removed by control 

equipment using information from the Electric Power Research Institute (EPRI) Estimating Total 

Sulfuric Acid Emissions from Stationary Power Plants: Version 2010a. EPRI, Palo Alto, CA: 

2010. 1020636, consistent with the methodology detailed in the Technical support document that 

accompanies the Oklahoma FIP. Rather than assuming that 100% of inorganic condensable PM 

is SO4, the EPRI method estimates the amount of SO2 that is oxidized to SO3 and then assumes 

that 100% of SO3 is converted to H2SO4. This methodology also accounts for loss of sulfuric 

acid due to downstream equipment, such as the air pre-heater, ESP or FF, and scrubber. 

 Total PM10 emissions should be estimated based on current PM emissions and the anticipated 

control efficiency or vendor guarantee of the proposed control equipment. The appropriate NPS 

worksheet and coal characteristics should be utilized to determine speciation (PMC, PMF, EC 

and SOA) given the total PM10 emissions (or filterable PM10). We note that if White Bluff 

upgrades the PM controls, the PM emission limit should be adjusted accordingly.