MITCIIELL WILLIAMS 

H. MAURICE MITCHELL 

(1925-2011) 

JOHN K. BAKER 

SHERRY P. BARTLEY 

STEVE BAUMAN 

R. T. BEARD, III 

C. DOUGLAS BUFORD, JR. 

BURNIE BURNER , 

FREDERICK K. CAMPBELL' 

MICHELLE H. CAULEY 

CHARLES B. CLIETT, JR.' 

KEN COOK 

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KAREN P. FREEMAN" 

ALLAN GATES' 

KATHLYN GRAVES 

HAROLD W. HAMLIN 

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ANTON L. JANIK, JR. I. 

M. SAMUEL JONES III 

TONY JUNEAU 

JOHN ALAN LEWIS 425 WEST CAPITOL AVENUE, SUITE 1800 

WALTER E. MAY LITTLE ROCK, ARKANSAS 72201-3525 

BRUCE MCCANDLESS III" TELEPHONE 501-688-8800 

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STUART P. MILLER 

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OF COUNSEL 

W. CHRISTOPHER BARRIER 

JOSEPH W. GELZINE 

DONALD H. HENRY 

"HERMANN IVESTER 

ANNE S. PARKER 

'LARRY PARKS 

JOHN S. SELIG 

MARCELLA J. TAYLOR 

RICHARD A. WILLIAMS 

I ONLY ADMITTED IN TEXAS 

2 ADMITTED IN DISTRICT OF COLUMBIA AND ARKANSAS 

3 ADMDTED IN ARIZONA, TEXAS AND ARKANSAS 

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5 A18979'89 IN TENNESSEE AND TEXAS 

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VIA EMAIL 

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December 23, 2013 

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AND TRADEMARK OFFICE AND ARKANSAS 

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ALL OTHERS ADMITTED ONLY IN ARKANSAS 

Ms. Mary Pettyjohn 

Air Division 

Arkansas Department of Environmental Quality 

5301 Northshore Drive 

North Little Rock, AR 72118 

Re: Arkansas Electric Cooperative Corporation BART Analysis 

Dear Ms. Pettyjohn: 

I am submitting on behalf of Arkansas Electric Cooperative Corporation ("AECC") a 

document containing its responses to the EPA's August 29, 2013 comments on the AECC BART 

analyses. As part of responding to the comments, AECC has made a few changes to the BART 

reports. In an effort to make the Arkansas Department of Environmental Quality's review of the 

changes as efficient as possible, AECC is submitting both redline and non-redline versions of the 

BART analyses. As such, you will find the following five files attached to this email: 

1. AECC Response to EPA BART FFA Comments Dated Aug 29 2013 12.23.13.pdf 

2. SO2 and PM10 BART Analysis REDLINE 12.23.13.pdf 

3. SO2 and PM10 BART Analysis NO REDLINE 12.23.13.pdf 

4. NOX BART Evaluation REDLINE 12.23.13.pdf 

5. NOX BART Evaluation NO REDLINE 12.23.13.pdf 

3097049.1 Mitchell, Williams, Selig, Gates & Woodyard, P.L.L.C. Attorneys at Law 

Arkansas 'Texas • New York MitchellWilliamsLawcom 
Ms. Mary Pettyjohn 

December 23, 2013 

Page 2 

Note, in documents 2 through 5 listed above, AECC is not resubmitting the modeling 

protocol as part of the appendices. The protocol is a large file, and would slow the transmittal of 

the files. Should you need another copy of this protocol, please let me know. 

Sincerely, 

MITCHELL, WILLIAiMS, SELIG, 

GATES & WOODYARD, P.L.L.C. 

By 

ht, Jr. 

WGW:jb 

Enclosures 

cc: Stephen Cain 

Jeremy Jewell 

Kasi Dubbs 

3097049.1 
AECC Responses to Comments on BART Analyses – December 23, 2013

1

Responses	to	EPA	comments	on	Five	Factor	Analyses	for	Bailey	and	

McClellan	Submitted	to	ADEQ	on	August	29,	2013.	

Note:  Several of the comments below reference EPA comments submitted on December 13, 2012.  

AECC did not receive the December 13, 2012 comments until September 04, 2013, so this is our first

opportunity to respond to those comments.

New Base Case for SO2

Comment 1

In comments provided to ADEQ on 12/13/12, we asked that the BART analysis include a justification for

the use of a new base case for SO2 and that documentation be provided of the historical actual sulfur

content of the fuel oil burned at the two units. AECC revised the BART analysis to explain that the new

base case values are representative of the average from 2009‐2011 and are also consistent with the

previous baseline years of 2001‐2003. However, no documentation of the sulfur content of the fuel oil

burned has been provided. Please provide this documentation to justify the new base case.  

Response 1 (See Sections 5.2.2 and 5.4.1 of the BART Analysis)

Table 1 below summarizes the annual average sulfur content of the No. 6 fuel oil historically used at

Bailey and McClellan.  The most recent fuel oil shipment for Bailey was in December of 2006, and the

most recent fuel oil shipment for McClellan was in April of 2009.  The fuel oil that has been stored at

Bailey since 2006 has an average sulfur content of 1.81 percent by weight, and the fuel oil that has been

stored at McClellan since 2009 has an average sulfur content of 1.38 percent by weight.   

Table 1.  Average Sulfur Content of Fuel Stored at Bailey and McClellan

Bailey McClellan

2000 1.59 1.84

2001 1.30 1.70

2002 1.69 2.21

2003 1.89 1.67

2004 1.07 1.60

2005 1.45 1.94

2006 1.33 2.08

2007 1.81 2.06

2008 1.81 2.18

2009 1.81 1.38

2010 1.81 1.38

2011 1.81 1.38

    

2001‐2003 average 1.63 1.86

2009 ‐ 2011 average 1.81 1.38
AECC Responses to Comments on BART Analyses – December 23, 2013

2

Table 1 has been added to the SO2 and PM BART analysis as Table 5‐7.   

In the EPA’s 2005 Regional Haze Rule BART Guidelines, EPA described baseline emissions as follows:

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

for the source... In the absence of enforceable limitations, you calculate baseline emissions based

upon continuation of past practice.”

Since EPA states that baseline emissions should be based on anticipated annual emissions and a

continuation of past practice, AECC used the sulfur content of the fuel oil currently stored at Bailey and

McClellan to estimate baseline emissions for Bailey Unit 1 and McClellan Unit 1.   

Cost Analysis for Fuel Switching (SO2 BART)

Comment 2

In a conference call with ADEQ and AECC in August 2012, AECC indicated the cost analysis for fuel

switching may have been based on outdated fuel oil cost numbers thereby potentially resulting in a cost

overestimation when compared to the cost in today’s market. However, the revised BART analysis does

not include any changes to the cost estimates and language was added stating that the cost numbers

are based on current vendor estimates for fuel oil with varying levels of sulfur, and are in fact

representative of today’s market available at Bailey and McClellan. Please provide a copy of the vendor’s

estimates. Additionally, the cost estimates shown on Tables 5‐9 and 5‐10 indicate that the cost of the

base case fuel is $4.68/MMBtu at Bailey and $5.70/MMBtu at McClellan. However, footnote 7 states the

cost estimate provided by the vendor for this type of fuel oil (i.e., No. 6 fuel oil with sulfur content

between 1.0 ‐ 2.0%) is between $16.00MMBtu ‐ $16.50MMBtu. This would indicate that the cost

differential of fuel switching is actually lower than what is currently estimated. Please explain the

apparent discrepancy in the cost estimates for the base case fuel oil.

Response 2

The vendor estimates for fuel pricing were provided during phone conversations between AECC staff

and fuel vendors.  There is no documentation from vendors that can be provided.  The reason for the

difference in cost for the baseline No. 6 fuel oil compared to No. 6 fuel oil that could be purchased by

AECC in the future is that the No. 6 fuel oil currently in the tanks at Bailey and McClellan was purchased

years ago when the price of oil was lower than it has been in the recent past.  The $4.68/MMBTU at

Bailey and $5.70/MMBTU at McClellan were calculated based on actual fuel oil purchases in prior years.  

The price of fuel oil has risen substantially since the existing fuel oil was purchased.  If the fuel oil in

AECC’s tanks was replaced with like‐kind fuel oil purchased today, then the cost of the replacement fuel

oil would be around $16/MMBTU.   

Modeling for SO2 BART

Comment 3

As we stated in comments provided to ADEQ on 12/13/12, section 1 of the BART analysis indicates the

pre‐control visibility impairment of each unit is based on modeling of emission rates that were derived
AECC Responses to Comments on BART Analyses – December 23, 2013

3

from stack testing, CEMS, and AP‐42 emission factors. However, it is still unclear how stack testing was

used to derive any of the emission rates modeled. Please explain how stack testing was used.

Response 3

Stack testing was not relied upon in the original BART analysis.  However, in developing these responses

to EPA comments, AECC has revised the total PM10 emission estimates relied on in the BART analysis

such that the PM10 emission rates are now based on stack testing of both filterable and condensable

PM10 conducted on Unit 1 at the McCllelan plant on May 29, 2013.  The total PM10 emission rate

determined during the testing was 59.4 lb/hr.  Thus, the BART analysis has been updated to use a total

PM10 emission rate of 59.4 lb/hr for McCllellan.  Stack testing was not conducted at Bailey in 2013,

however, AECC has relied on the data from the 2013 testing on Unit 1 at McClellan to estimate the total

PM10 emission rate for Unit 1 at Bailey.  Specifically, the PM10 emission rate used for McClellan was

scaled by the ratio of the heat input for Bailey vs McClellan (1436/1350) for a total PM10 emission rate of

55.8 lb/hr.

Comment 4

As we stated in our previous comments to ADEQ, the revised baseline max 24‐hour PM emission rates

(see Table 4‐1) are significantly lower than those used in the original BART analysis and appear to be

inconsistent with AP‐42 emission factors and the maximum burner capacities. Please explain the revised

PM emission rates and provide the PM emission estimation calculations.  

Response 4

Please refer to the response for Comment #3.

Comment 5

In our previous comments to ADEQ we stated that even though the visibility impacts from PM are

relatively small for both units, the visibility modeling of fuel switching scenarios should include the

decrease in PM emissions anticipated from switching to lower sulfur fuels. Since the PM emission rates

modeled did not account for the decreases in PM emissions as a result of fuel switching, we asked that a

brief discussion be included in the BART analysis on the impact of reductions of PM emissions on

visibility. Footnote 8 was added to explain that the PM emission rates for the lower sulfur fuel scenarios

are conservatively assumed to equal the baseline (i.e., higher) sulfur fuel scenario. However, a discussion

of the expected impact that adjusting the PM emission rates (to account for the decrease in PM

emissions in lower sulfur fuels) would have on the modeled visibility benefits has not been provided.  

Response 5

AECC conducted an analysis to estimate the impact that lower sulfur fuel oil would have on the PM10

emission rates.  The analysis was conducted as follows:

1. Start with the baseline emission rates for the PM10 species as determined using the NPS

workbook for residual oil‐fired boilers.

2. Assume the inorganic condensable particulate matter (CPM IOR) estimated for baseline

represents all sulfate particles.
AECC Responses to Comments on BART Analyses – December 23, 2013

4

3. Assume the reduction in the mass of the sulfate particles is equal to the reduction in the sulfur

content of the fuel oil when switching from the baseline fuel oil to a lower sulfur fuel oil.

4. Multiply the baseline rate for CPM IOR, which is assumed to be sulfates, by the percent

reduction in sulfur when switching from the baseline fuel oil to a lower sulfur fuel oil to get a

“controlled” rate for sulfates.

5. Divide the controlled rate for sulfates by the fraction of the total PM10 that is estimated by the

NPS to be CPM IOR to get a total PM10 rate that is reflective of the lower sulfur fuel.

6. Enter the total PM10 rate into the speciation workbook to determine the speciated PM10

emissions

Table 2 below summarizes the difference in the PM10 rates determined for baseline (as revised using the

McClellan 2013 stack test data) compared to the PM10 rates determined for the lower sulfur fuel oil

scenarios using the approach described above.

Table 2.  Speciated PM10 Emissions for Lower Sulfur Fuel Scenarios

Unit / Fuel

Total

PM10 SO4 PMc PMf SOA EC

Scenario (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr)

Bailey Unit 1

Baseline Fuel Oil 55.8 4.6 13.7 34.1 0.8 2.7

1% sulfur fuel oil No. 6 20.3 2.5 4.7 11.7 0.4 0.9

0.5% sulfur fuel oil No. 6 6.9 1.3 1.5 3.7 0.2 0.3

Diesel 0.4 0.1 0.1 0.2 0.0 0.0

McClellan Unit 1

Baseline Fuel Oil 59.4 5.9 14.2 35.4 1.0 2.8

1% sulfur fuel oil No. 6 34.6 4.3 8.0 19.9 0.8 1.6

0.5% sulfur fuel oil No. 6 11.7 2.1 2.5 6.2 0.4 0.5

Diesel 0.7 0.2 0.1 0.3 0.0 0.0

AECC also conducted an analysis to determine the impact of the PM10 emission rates shown in Table 2

above on the visibility improvement associated with the lower sulfur fuel oil scenarios.  The emission

rates shown in Table 2 were modeled using CALPUFF.  Table 3 compares the visibility impairment for the

lower sulfur fuel oil scenarios (from the July 2012 BART report) where the emission rates for the PM10

species were set equal to baseline (i.e. no credit was taken for any improvement to visibility impairment

associated with a reduction in PM10 emissions) to the visibility impairment for the lower sulfur fuel oil

scenarios where the emission rates shown in Table 2 were modeled.  As shown in Table 3, accounting

for a reduction in PM10 emissions for lower sulfur fuel oil does not make a significant impact on the

visibility determinations for the lower sulfur fuel oil scenarios.
AECC Responses to Comments on BART Analyses – December 23, 2013

5

Table 3. Comparison of Visibility Impairment for Bailey Unit 1 for Lower Sulfur Fuel Oil Scenarios

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness 

Maximum Impact(Δdv)

98% Impact(Δdv)

# Days> 0.5 Δdv

Visibility Improvement*

Maximum Impact(Δdv)

98% Impact(Δdv)

# Days> 0.5 Δdv

Visibility Improvement*

Maximum Impact(Δdv)

98% Impact(Δdv)

# Days> 0.5 Δdv

Visibility Improvement*

Baseline emission rates for the PM10 species held constant in the modeling of the lower sulfur fuel oil scenarios (See July 201

Baseline Emission Rate 0.969 0.330 8  ‐   0.695 0.347 7   ‐  0.686 0.367 6   ‐  1% sulfur fuel oil No. 6 0.547 0.195 1 40.91% 0.380 0.196 0 43.52% 0.411 0.208 0 43.32% 0.5% sulfur fuel oil No. 6 0.340 0.145 0 56.06% 0.234 0.132 0 61.96% 0.286 0.140 0 60.06% Diesel 0.217 0.087 0 73.64% 0.161 0.074 0 78.67% 0.228 0.073 0 80.11% 

Baseline emission rates for the PM10 species varied in accordance with Table 2 above in the modeling of the lower sulfur fu

Baseline Emission Rate – (fuel oil) 0.970 0.330 8  ‐  0.696 0.348 7  ‐  0.687 0.368 6  ‐  1% sulfur fuel oil No. 6 0.544 0.193 1 41.52% 0.377 0.194 0 44.25% 0.408 0.206 0 44.02% 0.5% sulfur fuel oil No. 6 0.333 0.142 0 56.97% 0.227 0.127 0 63.51% 0.279 0.135 0 63.32% Diesel 0.208 0.084 0 74.55% 0.156 0.069 0 80.17% 0.215 0.069 0 81.25% 
AECC Responses to Comments on BART Analyses – December 23, 2013

6

Comment 6

A new paragraph was added to page 5‐10 of the BART analysis, indicating AECC’s disagreement with our

previous comment about the need to use the maximum emission rate from the baseline period (instead

of the rolling 30‐day average) to calculate the SO2 emission rates to model for the fuel switching

scenarios. We continue to stand by our previous comment concerning this, and believe that if AECC

chooses to not re‐model at this time, then a discussion should be included of the impact, if any, that

using the maximum emission rates would have on the modeling results and the ultimate BART

determination.  

Response 6

Visibility modeling to determine BART applicability is based on a maximum 24‐hour emission rate.  A

comparison of the effectiveness of retrofit control technologies is typically based on a 30‐day average

emission rate.  While the use of two different averaging periods to establish baseline versus controlled

emission rates has been a common approach in BART analyses, it is possible this approach could

overstate the visibility improvement expected for a given control technology.  

In the preparation of the BART analysis, AECC recognized that the baseline and controlled emission rates

were based on different averaging periods.  However, since using a 30‐day average emission rate was a

conservative approach to estimating the visibility improvement expected from the various emission

reduction alternatives, AECC identified this approach as the best path forward.

AECC proposed the use of fuels with 0.5% sulfur or less for both Bailey Unit 1 and McClellan Unit 1.  This

is not a cost effective control option, but based on the level of visibility improvement associated with

fuel with 0.5% sulfur, AECC proposed this emission reduction option as BART.  The visibility

improvement for the proposed BART control is as high as 63% for Bailey Unit 1 (See Table 5‐13 of the

BART analysis, 0.5% sulfur No. 6 fuel oil, Upper Buffalo) and 50% for McClellan Unit 1 (See Table 5‐14 of

the BART analysis, 0.5% sulfur No. 6 fuel oil, Hercules Glades).   

AECC has compared the “existing” highest 24‐hour emission levels in lb/MMBtu to the existing highest

30‐day emission levels in lb/MMBtu used in the BART analysis.  A summary is included in Table 3 below.

Table 3.  Summary of SO2 Emissions – 24‐Hour vs 30 Day

Max 30‐Day

(lb/MMBtu)

Max 24‐Hour

(lb/MMBtu)

Increase from

from 30‐Day to

24‐Hour

Bailey Unit 1 1.59 2.66 40%

McClellan Unit 1 2.14 2.71 21%

  

As shown in Table 3, existing emission levels using a 24‐hour average are 21% and 40% higher for Bailey

and McClellan, respectively, than existing emission levels using a 30‐day average.  If this same variability

is assumed for the controlled rates, there would be a 21% and 40% increase in the controlled emission

rates for Bailey and McClellan, respectively.  An increase in the controlled emission rates of 21% and

40% for Bailey and McClellan, respectively, would result in an increase in the visibility impairment

attributable to the fuel switching scenarios of approximately 21% for Bailey Unit 1 and 40% for

McClellan Unit 1.  This means there would be a decrease in the visibility improvement for the control

scenarios.   
AECC Responses to Comments on BART Analyses – December 23, 2013

7

Comment 7

In our previous comments, we asked that the BART analysis include a plot showing the meteorological

domain, computational modeling domain, location of sources, and Class I area receptor locations used in

the visibility analysis. This plot has not been provided in the revised BART analysis.  

Response 7

Attachment A of this response includes two figures showing the meteorological domain, computational

modeling domain, location of sources, and the location of Class I area receptors

General comments on NOx BART

Comment 8

The new introductory section in the NOx BART analysis states that “As in the original submittal, it is

proposed to burn natural gas as the primary fuel and switch to low‐sulfur fuel oil as the back‐up fuel.” As

written, this statement seems confusing and out of place, as it is referring to BART for SO2,  and the SO2

BART analysis proposes to switch to fuels with 0.5% sulfur or less to satisfy BART. The SO2 BART analysis

makes no mention of proposing BART to be the burning of natural gas as the primary fuel and low sulfur

fuel oil to be burned only as the back‐up fuel. Therefore, we recommend that this statement be revised or

removed from the introduction.

Response 8

The statement related to the SO2 BART determination has been removed from the NOx BART analysis.  

Further, the SO2 BART determination proposed in the SO2 BART analysis has been revised to add clarity

to the BART proposal.  AECC’s original BART proposal for SO2 was worded as follows: AECC has

determined that BART for both Bailey Unit 1 and McClellan Unit 1 is switching fuels to fuels with 0.5%

sulfur or less.  The BART proposal is now worded as follows: AECC has determined that BART for both

Bailey Unit 1 and McClellan Unit 1 is using fuels with 0.5% sulfur or less (including using natural gas).   

Comment 9

Footnote 1 was added, stating that “The previously submitted SO2 and PM analyses were verbally

agreed upon by EPA in an August 16, 2012 conference call to discuss the July 24, 2012 submittal.” We

remind ADEQ that we communicated that we generally agreed with the SO2 and PM BART

determinations, but that certain issues needed to be addressed, in particular additional documentation

should be provided, to help support the analysis. To date, not all of these issues have been addressed, as

discussed in our comments above.

Response 9

AECC understands EPA’s concern; however, please note that the analysis was submitted to EPA before

AECC received EPA’s December 13, 2012 comments on the SO2 and PM BART analyses.  The December

13, 2012 comments were not received by AECC until September 04, 2013; therefore, this is our first

opportunity to respond to those comments.
AECC Responses to Comments on BART Analyses – December 23, 2013

8

NOx Control Case Emission Rates

Comment 10

Section 1.4.1.3 and Table 1‐2 state that based on the estimate provided by Babcock Power Services, the

NOx emission rate expected from the combination of LNB/OFA/FGR is 0.15 – 0.20 lb/MMBtu for both

natural gas and fuel oil firing scenarios. However, the copy of the estimate from Babcock Power Services

(Appendix C) indicates that the expected emission rate is 0.15 – 0.20 lb/MMBtu for natural gas firing,

and 0.35 lb/MMBtu for fuel oil firing. Please explain the inconsistency. We also note that Table 1‐2

indicates the baseline NOx emission rate for Bailey Unit 1 for fuel oil firing is 0.30 lb/MMBtu, which is

actually lower than Babcock Power Services’s expected emission rate of 0.35 lb/MMBtu using

LNB/OFA/FGR. Please provide an explanation addressing this.

Response 10

The cost information and emission rates provided by Babcock Power Services to AECC reflect estimates

based on combusting natural gas and No. 6 oil and do not represent emission guarantees.  Further, the

estimates are not specific to the fuel oil that AECC will likely burn as a result of the SO2 BART

determination.   

To get an actual guaranteed emission rate from a vendor for an EGU emission control retrofit would

take thousands of dollars and two to three months of vendor analysis.  This is because each boiler is

different and the vendor must build virtual models of a boiler and analyze it over multiple scenarios.  

Also, the vendor realizes that the likelihood of installation of emission controls on a relatively small EGU

with a low capacity factor (such as Unit 1 at Bailey or McClellan) is very unlikely.  So, the vendor has

absolutely no incentive to spend time and money to develop models and provide exact emission limits

or costs for a given unit.   

With all of this in consideration, the vendor provides an EGU operator with a range of NOx emission

values based on relatively simple estimates.   

Regarding the NOx estimate for fuel oil firing at Bailey, as mentioned above, the 0.35 lb/MMBTU NOx

emission value is a simple estimate from the vendor.  The 0.30 lb/MMBTU NOx emission value for the

baseline rate is from several years of certified CEMS data.  AECC believes a more refined estimate of

NOx emissions associated with combustion controls would show a lower achievable emission rate for

fuel oil.  AECC selected 0.15 lb/MMBtu in a conservative effort to represent what may be achievable.  

Using an emission level above 0.15 lb/MMBtu would lower the total tons controlled, which would

increase the cost per ton.  AECC has already determined that combustion controls are not cost effective.

AECC has expressed this concern to ADEQ.  It’s AECC’s understanding that ADEQ has contacted EPA

regarding this issue.

Comment 11

The estimate provided by Babcock Power Services for the capital cost of combustion controls and the

expected controlled emission rates, is for “Low NOx Natural Gas burners (#6 secondary fuel), OFA, and

FGR system (10%).” Please explain whether the 10% refers to the percentage of flue gas recirculated or
AECC Responses to Comments on BART Analyses – December 23, 2013

9

to the NOx removal efficiency of FGR alone. We note that FGR technology is typically capable of

recirculating 20‐30% of the flue gas back to the combustion zone. As you know the RH rule requires that

in analyzing controls for BART, the most stringent emission control level that the technology is capable of

achieving must be taken into account (70 FR 39166). ADEQ should ensure this requirement has been met.

Response 11

Upon receipt of these comments AECC attempted to contact Babcock Power Services via email and

asked them what the 10% referenced – the percentage of flue gas recirculated or to the NOx removal

efficiency of FGR alone.  As expected, AECC did not receive a reply from Babcock Power Services due to

the reasons listed in AECC’s response to Comment 10 above.   

Cost Analysis for NOx Controls

Comment 12

The capital costs for NOx combustion controls are based on the estimate provided by Babcock Power

Service. However, the O&M costs for combustion controls are still based on equations from the 2005 ERG

report prepared for the WRAP and based on coal fired EGU data. It has not been demonstrated that the

data and costing methods used are appropriate and applicable to the natural gas/fuel oil Bailey and

McClellan units. If it is not possible for AECC to incorporate site‐specific O&M costing information in the

cost‐analysis, a brief discussion should be provided of how the costs calculated using the equations from

the ERG report are in line with the actual costs of combustion controls at natural gas/fuel oil fired units

similar to the Bailey and McClelland units.

Response 12

AECC relied upon the ERG equations for coal‐fired boilers to estimate the O&M for low‐NOx burners on

our gas fired units, since these equations allowed us an approach for estimating O&M costs when we

had no other approach.  However, the O&M cost was not a significant component of the total annual

cost for either Bailey Unit 1 or McClellan Unit 1 and removal of this cost does not impact the BART

proposal in AECC’s NOx BART report.  The majority of the annual cost for both units is the capital

recovery.   

Table 1 below provides a cost estimate for combustion controls that does not include any O&M costs.

Table 4.  Cost Effectiveness Estimate for Combustion Controls (LNB/OFA/FGR) without O&M Costs

Parameters/Costs Description Bailey Unit 1 McClellan Unit 1

Capital Investment1 $7,700,000 $7,400,000

Capital Recovery Factor, 30-yr life, 7% interest

CRF = [ I x (1+i)^a]/[(1+i)^a - 1]

 I = interest rate, a = equipment life 0.08 0.08

Annual Capital Recovery Capital Investment * CRF $620,515 $596,339

Annual Tons NOx Reduced 18.98 119.15

Cost Effectiveness ($/ton) $32,692 $5,005

1: Capital Costs estimates provided by Babcock Power on February 28, 2013. The estimates do not represent a firm offer to sell but 

rather are good approximations that require further refinements before purchase.
AECC Responses to Comments on BART Analyses – December 23, 2013

10

Comment 13

The cost evaluation for combustion controls provided in Appendix A indicates it applies to LNB/OFA

capital and O&M costs. However, based on the capital costs shown, it appears that the cost information

presented in the table applies to LNB/OFA/FGR. If that is the case, please correct the title of the cost

evaluation accordingly.

Response 13

The title of the cost table has been changed to reflect the fact that it applies to LNB/OFA/FGR.

   
AECC Responses to Comments on BART Analyses – December 23, 2013

11

Attachment 1

Plots of Modeling Domain
"

"

EEEE

EE

E

EEE

BAILEY	

(SN‐01)

MCCLELLAN	

(SN‐01)

CANEY	CREEK

HERCULES	GLADES

MINGO

UPPER	BUFFALO

‐1,000

‐1,000

‐500

‐500

0

0

500

500

1,000

1,000

‐1,900‐1,900

‐1,600‐1,600

‐1,300‐1,300

‐1,000‐1,000

‐700‐700

‐400‐400

‐100‐100

Meteorological Modeling Domain

Computational Modeling Domain

Arkansas BART

Modeling Domain

LCC Northing (km)

LCC Easting (km)

Legend

" AECC	Sources

E Upper	Buffalo	Class	I	Area

E Mingo	Class	I	Area

E Hercules	Glades	Class	I	Area

E Caney	Creek	Class	I	Area

Domain	Boundary Page	1	of	2
"

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EE

EEE

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EEEEE

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EEEEEEEEEEEEEE

EEEEEEEEEEE

EEEEE

EEEEEEEEEE

EEE EEEEEEEEEEEEEE

EEEEEEE

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EEEE

EEEE

EEEE

EEEEEEEEEEEEEEEEEEEEE

EEE

EEEEEE

EEEEEEEEEEE

EEEEE

EEEEEEEEEEEEEEE EEEEEEEEEEEEEEEEEEEEEEEEE EEEEEEEEEE

BAILEY	

(SN‐01)

MCCLELLAN	

(SN‐01)

CANEY	CREEK

HERCULES	GLADES

MINGO

UPPER	BUFFALO

200

200

300

300

400

400

500

500

‐600‐600

‐550‐550

‐500‐500

‐450‐450

‐400‐400

‐350‐350

‐300‐300

‐250‐250

‐200‐200

Arkansas BART

Modeling Domain	‐	A Closer Look

LCC Northing (km)

LCC Easting (km)

Page	2	of	2