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 facili ty 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. Be low, however, we point out areas where additional documentation would be necessary to fully support th e 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 te chnology you take into account the most stringent emission control level that the tec hnology is capable of achieving” (70 FR 39166). ADEQ should demonstrate this requirement has b een 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 di scussions with vendors suggest that although a wet scrubber may be able to achieve up to 97% contro l 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 sc rubbers were evaluated at an outlet SO 2 emission rate of
0.06 lb/MMBtu and wet scrubbers at an outlet SO 2 emission rate of 0.04 lb/MMBtu. In section 5.4 it is stated that this repres ents 95% removal efficiency fo r the dry scrubber option and 97% removal efficiency for the wet scrubber option when applied to the units’ currently allowable
SO 2 emission rate of 1.2 lb/MMBtu. C onsidering that the 2001-2003 average SO 2 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 re moval 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 SO 2 emissions reductions expected to result from each control option (as shown in tables 5-7 and 5-8), it appears that dry scrubbers were ev aluated at 91.5% removal efficiency for Unit 1 and 90.5% for Unit 2 while we t scrubbers were evaluated at 94.3% removal efficiency for Unit 1 and 93.7% for Unit 2. ADEQ shoul d ensure that the requi rement 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 re port states that Entergy has concluded that the installation of a semi-dry sc rubber and baghouse is BART for SO 2 for both Units 1 and 2. However, the SO 2 controls evaluated in the BART re port 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 Appendi x A) contains line items related to the O&M costs of the baghouse, but there does not appear to be a line item for th e baghouse capital costs. Please specify whether the dry scrubbing technol ogy evaluated and selected as BART is NID or some configuration of SDA. In the cost evaluation of SO 2 controls Entergy assumed a 15 year equipment life for both wet and semi-dry scrubbers, based on a misinterpreta tion of the EPA Control Cost Manual (CCM). 1 EPA believes that 30 years is the more appropriate equipment life for scrubbe rs. If Entergy believes that the remaining useful life of the boilers affects the BART de termination, 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 ve ndors indicate that the lifetime of a scrubber is equal to the lifetime of the bo iler, which in some cases easily exceeds 60 years. The typical life for a scrubb er is reported as 30 years in pub lished papers and standard cost estimating handbooks. Since the capital costs are a nnualized over a period of time equal to the anticipated equipment life, a nd then added to the annual O& M costs to obtain the total annualized costs, the two SO 2 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 base d on vendor estimates for a system designed to achieve 97% control (0.06 lb /MMBtu) for an inlet SO 2 rate of 2.0 lb/MMBtu, and that the cost for a system designed to achieve an emi ssion rate of 0.04 lb/MMBtu for an inlet SO 2 rate of 1.2 lb/MMBtu would be approximately 5-6% higher. It does not app ear that Units 1 and 2 have historically burned coal containing 1.2 lb/MMBtu SO 2 . To properly evaluate cost-effectiveness,
controls should either be desi gned to burn coal with the same sulfur content as has been historically used at the units ( 2001-2003), or if the cont rols evaluated are designed to burn coal with a higher sulfur content than has been hist orically used at the units, ADEQ should ensure
that the baseline is raised to correspond with the sulfur conten t 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 comm ents were provided on the draft Title V/Prevention of Significant Dete rioration (PSD) permit for White Bluff. In that letter, EPA agreed that dry scrubber technology is one of the SO 2 controls generally accepted as BART. Although that statement, offered in another re gulatory 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 SO 2 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 th an currently achieved by the existing ESPs, ADEQ should re-evaluate the BART limits previously es tablished 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 SO 2 controls included undocumented co sts, line items that should be identified/explained, as well as some costs th at are not allowed under the CCM. According to the CCM, AFUDC costs are not allowed in estimati ng capital costs for controls. In addition, for the semi-dry scrubber cost evaluati on, 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 contract or 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 pr ovide a breakdown of total equipment costs, purchased equipment cost, and direct annual costs.

2. NOx BART

 Although FGR is identified as a technically feas ible 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 remai nder of the BART report, or incl ude it in the BART analysis.

 In Tables 6-7 and 6-8, Entergy i ndicates that it evaluated LNB/SO FA to achieve 51% control at Unit 1 and 58% control at Unit 2. However, ba sed on the annual NOx emissions reductions expected to result from LNB/SO FA, it appears that th is 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 th e discrepancy or re vise 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 ha s been taken into account (70 FR 39166).

 Please provide a copy of the “2012 S&L NOx St udy” referred to in footnotes 36-38. The
emission rates evaluated for each NOx control scenar io and the estimates for capital costs, fixed O&M costs, and some of the variable O&M co sts 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 SO 2 controls, AFUDC costs we re 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 Enter gy 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 Ente rgy believes that the remaining
useful life of the boilers aff ects 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 bo ilers by a date certain.

3. Auxiliary Boiler (SN-05)

 Please provide modeling files for baseline modeli ng for SN-05 as well as baseline modeling for the three subject-to-BART units combined.

 Please explain how baseline maximum 24-hr emissi ons for SN-05 were calculated. We note that
the modeled emissions for SO 2 of 5.8 lb/hr differ from the base line emission rate modeled in the
SIP of 32.5 lb/hr.

 Are there any limitations to the hou rs of operation of this unit? Wh at are the historical hours of operation of this unit? ADEQ should explain why the baseline is represen tative 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 base line visibility modeling showed that there is no opportunity for visibility improvement attributab le to SN-05, because not a single day greater
than 0.5 Δ dv is associated with SN-05, it is not possi ble to install control equipment to improve visibility. Therefore, no controls is the SO 2 BART (NOx BART) determination for SN-05.” This is not an appropriate justifi cation for not completing a BART analysis for the unit. The 0.5 dv threshold applies only to the determination of wh ether the facility, considering all BART eligible units, is subject to BART. 2 We note that in some cases, stat es may adopt a more streamlined approach to making BART determinations wher e appropriate. For example, a State need not undertake an exhaustive analysis where it is clear that controls w ould be costly and any improvements in visibility resulting from re ductions 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 improveme nts 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 ca ses, all inorganic PM
was assumed to be SO 4 . This assumption and assumptions of SO 4 reductions due to controls impacts the baseline modeling as well as the visi bility benefit from WFGD when compared to
NID. We recommend that sulfuric acid emi ssions from power plan ts are calculated by estimating the amount of H 2 SO 4 produced and the amount of H 2 SO 4 removed by control equipment using information from the Electric Po wer Research Institute (EPRI) Estimating Total Sulfuric Acid Emissions from Stationary Po wer 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 as suming that 100% of inorganic condensable PM
is SO 4 , the EPRI method estimates the amount of SO 2 that is oxidized to SO 3 and then assumes
that 100% of SO 3 is converted to H 2 SO 4 . This methodology also accounts for loss of sulfuric acid due to downstream equipment, such as th e 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 pr oposed control equipment. The appropriate NPS
worksheet and coal characteristic s should be utilized to determ ine speciation (PMC, PMF, EC and SOA) given the total PM10 emissions (or filt erable PM10). We note that if White Bluff upgrades the PM controls, the PM emission lim it should be adjusted accordingly.