Appendix A. 

Technical Support Document 

for the 

SDA Control Cost Analysis for the Entergy White Bluff and Independence 

Facilities 

Arkansas Regional Haze Federal Implementation Plan 

(SO2 Cost TSD) 

Prepared and Reviewed by: 

Joe Kordzi 
ii 

Dayana Medina 

February 2015 

Table of Contents 

1. Introduction .............................................................................................................................. 1

2. SDA Cost Analyses Methodology ........................................................................................... 1

2.1. Our Critique of the Entergy White Bluff SDA Cost Analyses ..................................... 2

2.2. Basic Points of Agreement with Entergy ..................................................................... 2

2.3. Use of the 2009 Alstom Cost Analysis ......................................................................... 2

2.4. Use of the S&L Balance of Plant Costs ........................................................................ 3

2.5. Undocumented or Disallowed Cost Items .................................................................... 7

2.5.1. Capital Suspense and Entergy Internal Costs .................................................... 7

2.5.2. BOP Indirect Cost .............................................................................................. 8

2.5.3. Miscellaneous Contractor Labor ....................................................................... 8

2.6. Entergy’s Cost Escalation Methodology ...................................................................... 8

2.7. Entergy’s Operating and Maintenance Costs ............................................................... 9

3. Adjusted SDA Cost Effectiveness Calculations for the White Bluff and Facility ................ 10

3.1. Entergy’s Coal Sulfur Assumption ............................................................................. 11

3.2. Adjusting Entergy’s SDA Costs for Coal Sulfur Content .......................................... 12

4. Calculation of SDA Cost Effectiveness for the White Bluff Facility .................................... 14

4.1. Conservative Aspects of our White Bluff SDA Cost Analysis .................................. 16

5. Extension of the White Bluff SDA Cost Analysis to the Independence Facility .................. 16

6. White Bluff Wet Scrubbing Cost Analysis ............................................................................ 19

6.1. Our Critique of the Entergy White Bluff Wet FGD Cost Analysis ............................ 19

7. Calculation of Wet FGD Cost Effectiveness for White Bluff and Independence ................. 22

List of Tables 

Table 1. Excluded BOP costs ......................................................................................................... 5

Table 2. Adjustment to Remaining Entergy BOP Costs ................................................................ 6

Table 3. Total Reductions in Entergy’s BOP Costs ....................................................................... 7

Table 4. CEPCI Values used in Entergy’s SDA Calculation......................................................... 9

Table 5. Base Adjusted SDA Cost Calculations .......................................................................... 10

Table 6. Entergy Annual Average Monthly Emission Rate ........................................................ 11

Table 7. IPM SDA Cost Analysis Using Entergy’s Input Values ............................................... 13

Table 8. Results of IPM SDA Cost Analyses Using Historic vs. Design Coals .......................... 14

Table 9: EPA Calculated SDA Cost Effectiveness for White Bluff Unit 1 ................................. 15

Table 10: EPA Calculated SDA Cost Effectiveness for White Bluff Unit 2 ............................... 15

Table 11: EPA Calculated SDA Cost Effectiveness for Independence Unit 1 ............................ 18

Table 12: EPA Calculated SDA Cost Effectiveness for Independence Unit 2 ............................ 18

Table 13. Base Adjusted Wet FGD Cost Calculations ................................................................ 20

Table 14. IPM Wet FGD Cost Analysis Using Entergy’s Input Values ...................................... 21

Table 15. Results of IPM Wet FGD Cost Analyses Using Historic vs. Design Coals ................ 22

Table 16: EPA Calculated Wet FGD Cost Effectiveness for White Bluff Unit 1 ....................... 23

Table 17: EPA Calculated Wet FGD Cost Effectiveness for White Bluff Unit 2 ....................... 23

Table 18: EPA Calculated Wet FGD Cost Effectiveness for Independence Unit 1 .................... 24
iii 

Table 19: EPA Calculated Wet FGD Cost Effectiveness for Independence Unit 2 .................... 24

 
iv 

List of Figures 

Figure 1. Satellite Photograph of the White Bluff Facility .......................................................... 17

Figure 2. Satellite Photograph of the Independence Facility ....................................................... 17
 

SDA Control Cost Analysis for the Entergy White Bluff and Independence 

Facilities 

Arkansas Regional Haze Federal Implementation Plan 

1. Introduction 

This TSD describes how we conducted control cost analyses for retrofitting certain coal fired 

EGUs with Spray Dryer Absorbers (SDA, or dry scrubbers) and wet Flue Gas Desulfurization 

(wet FGD). This work is a part of our review of the Arkansas Regional Haze State 

Implementation Plan (SIP). We are conducting this control cost analyses under the BART 

provisions of the regional haze rule for Units 1 and 2 of the Entergy White Bluff facility, and 

under the reasonable progress provisions of the regional haze rule for Units 1 and 2 of the 

Entergy Independence facility. 

We have constructed a spreadsheet1 that contains information concerning ownership, location, 

boiler type, environmental controls and other information that we draw upon throughout this 

appendix. This spreadsheet includes information contained within EIA Forms 860 and 923. We 

have also constructed a spreadsheet that contains most of the calculations referenced within this 

TSD.2 Other pertinent documents are cited with this TSD. All of this information is present in 

our docket. 

2. SDA Cost Analyses Methodology 

In developing our cost estimates for the units in Table 1, we relied on the methods and principles 

contained within the EPA Air Pollution Control Cost Manual.3 As we describe in our Oklahoma 

final action,4

 the CCM uses the “overnight” method of cost estimation: 

The Control Cost Manual uses the overnight method of cost estimation, widely 

used in the utility industry. The U.S. Energy Information Administration (EIA) 

defines ‘‘overnight cost’’ as ‘‘an estimate of the cost at which a plant could be 

constructed assuming that the entire process from planning through completion 

could be accomplished in a single day. This concept is useful to avoid any impact 

of financing issues and assumptions on estimated costs.’’ EIA presents all of its 

projected plant costs in terms of overnight costs. The overnight cost is the present 

value cost that would have to be paid as a lump sum up front to completely pay 

for a construction project. The overnight method is appropriate for BART 

determinations because it allows different pollution control equipment to be 

compared in a meaningful manner. Because ‘‘different controls have different 

expected useful lives and will result in different cash flows, the first step in 

comparing alternatives is to normalize their returns using the principle of the time 

 

1

 “EIA Consolidated Data_WB and Ind_Y2012.xlsx.” 

2

 “White Bluff_R6 cost revisions2.xlsx.” 

3

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

http://www.epa.gov/ttncatc1/dir1/c_allchs.pdf. 

4

 77 FR 81744. 
2 

value of money ... The process through which future cash flows are translated 

into current dollars is called present value analysis. When the cash flows involve 

income and expenses, it is also commonly referred to as net present value 

analysis. In either case, the calculation is the same: Adjust the value of future 

money to values based on the same point in time (generally year zero of the 

project), employing an appropriate interest (discount) rate and then add them 

together.’’ 

Our proposed approach is as follows: 

 Start with material we and Arkansas received from Entergy to support its White Bluff 

control cost analysis. 

 Analyze that material for compliance with the Regional Haze Rule and our guidance. 

 Critique that material and adjust it as necessary. 

 Justify and extend that analysis to the Independence facility. 

2.1. Our Critique of the Entergy White Bluff SDA Cost Analyses 

We proceed in our SO2 costing analyses by starting with the revised BART analysis for the 

White Bluff facility, as submitted by Entergy on October 14, 2013 (hereafter referred to as the 

“2013 SDA Cost Analysis”).5 Regarding an earlier version of this analysis, Entergy states6 that 

they received two different SDA cost estimates for white Bluff: an early 2009 Sargent and 

Lundy (S&L) estimate with a total contractor cost of $291,930,000, and a December 2009 

estimate from Alstom of $247,856,184. Entergy states that unlike the S&L quote, the Alstom 

estimate was not itemized and only included a total price. Entergy uses the 2009 Alstom price 

quote as the basis for its BART cost analysis for White Bluff by increasing it by 10%, and 

scaling the S&L itemized cost to match the 110% adjusted Alstom total price. Below we outline 

which parts of Entergy’s analysis we propose to agree with and with which we propose to 

disagree. For the latter, we propose adjustments. 

2.2. Basic Points of Agreement with Entergy 

We propose to use Entergy’s adjusted 2009 Alstom SDA cost estimate and its resulting itemized 

cost analysis as the basis for Entergy’s White Bluff cost analysis, although we propose a number 

of adjustments. We also prose to accept Entergy’s determination that considering the coal 

burned, that a reasonable maximum control level for the White Bluff facility for SDA is 0.06 

lbs/MMBtu, on a 30 day average basis.7

 However, as we have done in FIPs in the past in 

response to facility requests, we believe that a 30 day Boiler Operating Day (BOD) average is 

more appropriate than a straight 30 day rolling average.8

2.3. Use of the 2009 Alstom Cost Analysis 

 

5

 Revised Bart Five Factor Analysis, White Bluff Steam Electric Station, Redfield, Arkansas AFIN 35-00110), 

Trinity Consultants, Inc., October 2013. 

6

 Entergy Response to EPA Region 6 comments on Entergy White Bluff draft BART Report, 06/10/13, page 7. 

7

 Please see our TSD for the Oklahoma FIP. 

8

 76 FR 81747. 
3 

Entergy states that it has received a quote from Alstom for the installation of two semi-dry SO2

scrubbing systems, and that it has received control cost analyses from S&L for SDA, wet FGD, 

and other controls. It notes that the “the total contract price for the two semi-dry scrubbing 

systems included in Alstom’s December 2009 payment schedule ($247,856,184) is less than the 

cost estimate provided by S&L to Entergy in early 2009 ($291,930,000).”9

 Furthermore, 

Entergy states that it cancelled the contract with Alstom in 2010, and that Alstom informed it 

that if it wanted to continue with the project, that the price would increase by 10%. Alstom 

states the resulting cost is $272,197,128. For the purposes of its 2013 SDA Cost Analysis, 

Entergy selected the lower Alstom quote, after adjusting it for the 10% price increase. We 

assume Entergy rounded the Alstom price increase, since an additional 10% would result in a 

cost of $272,641,802. In any case, this adjusted quote presents a number of difficulties: 

 Entergy does not provide the scope of the Alstom quote, so we must assume that it 

includes the items in its payment schedule, but do not know if other items are also 

included. Also, other than a projected payment schedule10 with a total price quoted at the 

end, Entergy does not provide any documentation for the Alstom price quote. It has been 

our experience that an itemized total contract price is provided, rather than a simple total. 

 Entergy does not provide documentation of Alstom’s 2010 10% price increase. 11 

 Although the Alstom payment schedule does not provide line item costs, it does provide a 

fairly comprehensive summation of the work that Alstom included in its quote. In the 

following section, we outline why we believe some of the work Entergy includes in its 

Balance of Plant costs is already included in the Alstom quote. 

We invite Entergy to provide clarifications to these issues. 

2.4. Use of the S&L Balance of Plant Costs 

Entergy uses the Balance of Plant (BOP) costs from a 2008 S&L quote12 to supplement its 

adjusted Alstom quote in its 2013 SDA Cost Analysis. However, it appears that a number of 

items are either not appropriate for a SO2 scrubber, or are already covered as part of the Alstom 

quote: 

 Item 106.1 of the BOP quote lists a “Reagent Prep Enclosure” with a total cost of 

$687,000. Line Items 107.1, 107.2, and 107.3 lists items associated with a reagent 

handling system, including unnamed equipment, lime storage silos, and a railcar 

unloading shed and dust collection, with a total material and labor cost of $20,542,000. 

 

9

 Entergy Response to EPA Region 6 comments on Entergy White Bluff draft BART Report 

06/10/13. Page 7 and Table 1. 

10 Entergy Response to EPA Region 6 comments on Entergy White Bluff draft BART Report, 06/10/13. 

Attachment A. 

11 Cost escalation is commonly done (though not exclusively) using the Chemical Engineering Plant Cost Index. 

Note that the CEPCI for 2010 is 550.8, versus that for 2009 being 521.9. Entergy itself uses this method to escalate 

costs in performing its control cost analysis. Escalation of the 2009 Alstom quote using the CEPCI would result in a 

cost of 550.8/521.9 X $247,856,184 = $261,581,119. 

12 Entergy Response to EPA Region 6 comments on Entergy White Bluff draft BART Report, 06/10/13. 

Attachment B. 
4 

However, the Alstom quote indicates that a purchase order for a “Lime system” was 

scheduled to be issued in month 7. The description states this is a “Lime storage and 

preparation system.” Since lime is the reagent for a SDA system, we assume the Alstom 

quote for a lime storage and preparation system included everything necessary to store, 

prepare, and convey the lime to the SDA system, including these items. Thus, we believe 

these costs, totaling $21,229,000, should be subtracted from the BOP quote. 

 Items 108 and 109 of the BOP quote cover low NOx control equipment for Units 1 and 2 

for a total cost of $16,590,000. We assume this was an oversight by Entergy, since NOx 

controls are not a part of the installation of a SDA system. We therefore subtract these 

costs from the BOP quote. 

 Items 111 and 112 of the BOP quote lists flue gas system ductwork for Units 1 and 2 for 

a total cost of $1,754,000. The Alstom quote indicates that the procurement of flue gas 

ductwork is initiated in months 8 and 10, with ductwork delivery, fabrication, and 

completion occurring in later months. It therefore appears to us that flue gas ductwork 

should not be included in the BOP quote. 

 Item 111.2 of the BOP quote lists a charge of $255,000 to paint the chimney. This 

appears to be a maintenance item so we subtract this cost from the BOP quote. If in fact 

it is a necessary part of the installation of the SDA system, we invite Entergy to provide 

clarification. 

 Items 113 and 114 of the BOP quote cover booster fans for Units 1 and 2 for a total cost 

of $1,166,000. The Alstom quote indicates that booster fans are scheduled to be 

delivered in month 22, and installed in month 30. Therefore we subtract this charge from 

the BOP quote. 

 Item 211.1 of the BOP quote covers CEMS (Continuous Emission Monitoring System) 

refurbishing for a total cost of $390,000. Since this appears to be a maintenance item, we 

subtract it from the BOP cost. 

These cost adjustments are summarized below: 
5 

Table 1. Excluded BOP costs 

Acct. 

No. Description Equipment Material Labor Total 

106.1 Reagent Prep Enclosure 0 $195,000 $492,000 $687,000

107.1 Equipment $7,012,000 0 $5,610,000 $12,622,000

107.2 4200 Ton Lime Storage 

Silos 

0 $2,428,000 $5,038,000 $7,520,000

107.3 Enclosed Railcar 

Unloading Shed 

0 $200,000 $200,000 $400,000

108 Unit 1 NOx Controls $3,622,000 $1,600,000 $3,073,000 $8,295,000

109 Unit 2 NOx Controls $3,622,000 $1,600,000 $3,073,000 $8,295,000

111 Unit 1 Flue Gas System 0 $364,000 $513,000 $877,000

111.2 Paint Chimney 0 $100,000 $155,000 $255,000

112 Unit 2 Flue Gas System 0 $364,000 $513,000 $877,000

Totals for Excluded BOP Items $14,256,000 $6,851,000 $18,667,000 $39,828,000

Totals for all BOP Items 

Excluding Percentage Costs 

$45,561,000 $35,120,000 $80,863,000 

Percentage BOP Items Reduced 31.29% 19.51% 23.09% 

The Entergy BOP quote includes a number of items (Items 301 through 308) that are either 

calculated as percentages of the equipment, materials, or labor; or are directly related to 

them. For instance, Item 301.2 of the BOP quote covers “Mobilize/Demobilize” costs, which 

are calculated as 1% of labor, which Entergy calculated as being $710,000. Similarly, Item 

304.2 covers “Cost Due to Overtime – 5-10s” which is not calculated as a percentage of 

labor, but which obviously is related to the total labor needed to install the pertinent 

equipment. Because as summarized in the table above, we have excluded certain costs from 

the BOP quote, we believe it is appropriate to adjust the additional BOP costs that are based 

on those costs. Therefore, we have reduced these costs by the corresponding percentages we 

have calculated in the above table for the appropriate cost category. For instance, since Items 

301.2 and 304.2 are functions of the total labor, and we are proposing to reduce the labor 

charges by 23.09%, Items 301.2 and 304.2 are also reduced by this amount. These 

adjustments are shown in the table below:
6 

Table 2. Adjustment to Remaining Entergy BOP Costs13

13 See “White Bluff_R6 cost revisions2.xlsx,” tab BOP 

ACCT.

NO. DESCRIPTION

ENTERGY

TOTAL

EQUIPMENT

COST

ENTERGY

TOTAL

MATERIAL

COST

ENTERGY

TOTAL

LABOR COST

ENTERGY

TOTAL COST

EPA TOTAL

EQUIPMENT

COST

EPA TOT

MATER

COST

301 MOBILIZE/DEMOBILIZE @ 1% OF LABOR

301.2 MOBILIZE/DEMOBILIZE @ 1% OF LABOR $710,000 $710,000 

302 COST DUE TO OVERTIME ‐ 5‐10'S

302.2 COST DUE TO OVERTIME ‐ 5‐10'S $10,363,000 $10,363,000 

304 PER DIEM ‐ @ $10 PER HOUR

304.2 PER DIEM ‐ @ $10 PER HOUR $10,257,000 $10,257,000 

305 SPARE PARTS @ 1% OF EQUIPMENT

305.2 SPARE PARTS @ 1% OF EQUIPMENT $476,000 $476,000 $327,060 

306 FREIGHT @ 5% OF MATERIAL

306.4 FREIGHT @ 5% OF MATERIAL $1,756,000 $1,756,000 $1,413

307

GENERAL & ADMINISTRATIVE (G&A) @ 5% OF

MATERIAL AND LABOR

307.5

GENERAL & ADMINISTRATIVE (G&A) @ 5% OF

MATERIAL AND LABOR $1,756,000 $3,143,000 $4,899,000 $1,413

307.6

GENERAL & ADMINISTRATIVE (G&A) @ 5% OF

MATERIAL AND LABOR $1,456,000 $1,456,000 

308 PROFIT @ 10% OF MATERIAL AND LABOR

308.5 PROFIT @ 10% OF MATERIAL AND LABOR $3,512,000 $6,285,000 $9,797,000 $2,826

308.6 PROFIT @ 10% OF MATERIAL AND LABOR $2,913,000 $2,913,000 

360 NON CONTRACTOR INDIRECTS

360.8 ENGINEERING ‐ BOP $9,855,000 $9,855,000 

TOTALSREDUCTION IN BOP COSTS

ENTERGY 

$52,482,000 
7 

The table below summarizes the reductions we propose to make to Entergy’s BOP costs: 

 

Table 3. Total Reductions in Entergy’s BOP Costs 

Entergy’s Original BOP Costs $204,171,000 

EPA Excluded BOP Costs -$39,828,000 

EPA Adjustments to Remaining BOP Costs -$11,905,667 

Total $152,437,333 

These costs, which equate to a reduction of $51,733,667 ($25,866,833.50 per unit) are further 

adjusted to account for errors in escalation, as is described in a later section, below. 

2.5. Undocumented or Disallowed Cost Items 

In the following sections, we discuss costs proposed by Entergy in its 2013 SDA Cost Analysis, 

which we believe should not be a part of its SDA cost analyses, because those costs have not 

been documented, appear to be already covered in other cost items, or do not appear to be valid 

costs under the Control Cost Manual methodology. 

2.5.1. Capital Suspense and Entergy Internal Costs 

Entergy’s adjusted Alstom SDA quote contains charges for “Capital suspense,” and “Entergy 

Internal Costs.” Regarding capital suspense, Entergy states14: 

Capital suspense is a distribution of overhead costs associated with 

administrators, engineers, and supervisors and includes function specific rates 

and A&G (Corporate Accounting) rates. Function specific capital suspense is 

dependent upon the personal hours allocated to a specific project for a time 

period. However, the percent of a total project that is dedicated to capital 

suspense is not a constant. Rather, it is dependent upon the yearly total capital 

expense budget and the budgeted capital spending for a specific function. Based 

on Entergy’s experience with hours required in similar projects, a 2% of total 

capital has been assumed to represent the future capital suspense of the project. 

Regarding “Entergy Internal Costs,” Entergy states, “Entergy internal costs include ESI labor, 

construction site labor, travel and loader costs. No documentation of these costs was provided. 

Both of these cost categories include labor, administrative, and related elements that appear to be 

present elsewhere in the BOP costs discussed above. We are also unable to locate these costs in 

the Control Cost Manual, but invite Entergy to provide clarification. We are therefore proposing 

that these items be deleted from Entergy’s SDA cost calculation. 

 

 

14 Entergy Response to EPA Region 6 comments on Entergy White Bluff draft BART Report 

06/10/13. Page 9. 
8 

2.5.2. BOP Indirect Cost 

In addition to the BOP costs that we discuss above, Entergy also includes a BOP indirect cost of 

$8,733,104 per unit. Regarding this, Entergy states15: 

BOP indirect costs are costs associated with engineering, construction 

management, startup and commissioning and are estimates provided by the 

contractor. Miscellaneous contractor labor is inclusive of legal support, owner’s 

insurance, S&L engineering costs, and Entergy’s environmental permitting costs. 

No documentation of these costs was provided. We agree that BOP indirect costs are certainly 

legitimate under the Control Cost Manual. However, the BOP quote discussed above already 

contains Item 360, entitled “Non Contractor Indirects,” under which is the subcategory Item 

360.8 entitled “Engineering BOP,” for $9,855,000. Furthermore, we note that the BOP quote 

also contains two additional charges for “General and Administration” (Items 307.5 and 307.6) 

for a total of $6,355,000. These General and Administrative and Non Contractor Indirects 

categories are broad in scope, unspecific in description, and undocumented. Together, they total 

$16,210,000. Lacking any documentation to the contrary, we therefore assume any work 

associated with the support or administration of the BOP items are contained within these cost 

items. We therefore propose to delete the additional BOP indirect cost item from the SDA costs. 

2.5.3. Miscellaneous Contractor Labor 

Entergy includes a cost entitled “Misc Contractor Labor,” regarding which it notes16, “Misc 

contract labor includes permitting and regulatory support.” No documentation was provided. As 

noted above, Entergy states that the BOP indirect costs we propose to delete also include charges 

for permitting costs. Thus, lacking any documentation to the contrary, it appears this cost is at a 

minimum already accounted. As with the BOP indirect cost, we assume any work associated 

with the support or administration of the BOP items are contained within the General and 

Administrative and Non Contractor Indirects categories already present in the BOP quote. We 

therefore propose to delete the Miscellaneous Contractor Labor cost item from the SDA costs. 

2.6. Entergy’s Cost Escalation Methodology 

As is usual practice, and in accordance with the Control Cost Manual, costs can be escalated 

from older vendor quotes or contractor estimates to the point in time at which the control cost 

calculation is being performed.17 This is done through the use of escalation indices by 

multiplying the older cost by the ratio of the newer index to that of the older index. Escalation 

for air pollution controls at power plants and other large sources is typically done using the 

Chemical Engineering Plant Cost Index (CEPCI). When escalating costs that include a range of 

 

15 Entergy Response to EPA Region 6 comments on Entergy White Bluff draft BART Report 

06/10/13. Page 9. 

16 Revised Bart Five Factor Analysis, White Bluff Steam Electric Station, Redfield, Arkansas (AFIN 35-00110). 

Appendix A, SDA cost analysis. 

17 Escalation to current dollars is in accordance with the Overnight Method employed by the Control Cost Manual. 

Escalation during the construction period (which was not included by Entergy in its SDA cost calculation), however, 

is not in accordance with the Overnight Method. 
9 

cost items, it is appropriate to use the CEPCI composite index, which is constructed from four 

sub-indices: equipment, construction labor, buildings, and engineering and supervision. Also, 

the annual composite CEPCI is constructed from the annual average of the monthly composite 

CEPCI indices, and should be used when escalating from year to year. For instance, a 2009 cost 

could be escalated to 2013 dollars by multiplying that cost by (567.3/521.9). Here, the 2013 

CEPCI annual index is 567.3 and that for 2009 is 521.9. 

However, in its SDA cost analysis, it appears Entergy used incorrect CEPCI indices, as the 

following table indicates: 

Table 4. CEPCI Values used in Entergy’s SDA Calculation 

Year Entergy CEPCI EPA CEPCI 

2008 530.7 575.4

2010 533.0 550.8

2012 (January) 593.6 584.6

2013 Not used 567.3

In the above table, we have added the correct annual CEPCI composite indices in the right-most 

column. Entergy indicates that it used the January index for 2012 (presumably because the 2012 

annual index would not have been available until April, 2013). We do not believe this practice is 

appropriate, since monthly CEPCI indices can vary quite a bit with a given year. In any case, it 

appears that Entergy mistakenly used the January index for each year to represent the entire year. 

In our SDA cost analysis, we adjust Entergy’s escalation through the use of the correct annual 

CEPCI composite indices. 

2.7. Entergy’s Operating and Maintenance Costs 

Regarding its operating and maintenance costs (direct annual costs), Entergy states, “[t]he O&M 

cost estimates are based on the Sargent & Lundy economic model from May 2008.”18 This 

information was not supplied, thus we have no way of verifying these costs. However, we can 

compare Entergy’s O&M costs to those obtained through the use of our IPM SDA cost model.19 

Entergy lists the 2008 total direct annual cost as being $7,901,369. This figure is composed of 

operating labor and materials, water, waste disposal, bag replacement. Entergy also lists the 

2012 total indirect cost as being $43,290,224. Subtracting out the annualized capital, property 

tax, and insurance costs, results in a cost of $9,580,310.20 De-escalating this figure to 2008 

yields a cost of $8,565,146.21 Thus, the total annual operating costs are $16,466,515. Together, 

these costs are approximately equivalent to what is typically referred to as the annual variable 

and fixed operating costs. 

 

18 Revised Bart Five Factor Analysis, White Bluff Steam Electric Station, Redfield, Arkansas (AFIN 35-00110). 

Appendix A, SDA cost analysis. 

19 IPM Model – Updates to Cost and Performance for APC Technologies, SDA FGD Cost Development 

Methodology, Final, March 2013. 

20 We are leaving in an administrative charge of $6,702,678, as we believe this charge is included in our IPM SDA 

cost methodology, against which we make our comparison. 

21 In so doing, we use Entergy’s incorrect 2008 and 2012 CEPCI, as these were used to escalate to 2012. 
10 

Configuring our IPM SDA cost model for the White Bluff Unit 1, using Entergy’s own input 

values (e.g., 2.0 lb/MMBtu SO2, lime, water, labor, aux. power, waste disposal),22 results in a 

total annual variable and fixed operating cost of $21,285,940.23 Although we input Entergy’s 

2008 input values, we note that the underlying costing algorithms reflect 2012 pricing, which 

may impact operational cost pricing. We therefore expect it to yield higher costs, which it does 

in this instance. We consequently believe that these costs compare favorably with Entergy’s 

operational and maintenance costs, and therefore accept Entergy’s calculations. 

Entergy also calculates property tax and insurance costs, with each being equal to 1% of the total 

capital investment, stating these costs are based on calculation methods from our Control Cost 

Manual for wet acid gas absorber systems. We adopt this calculation methodology as well, but 

note that the calculated values will change because we have lowered the total capital investment 

due to the undocumented and disallowed cost items described above. 

3. Adjusted SDA Cost Effectiveness Calculations for the White Bluff and Facility 

Below is a summary of the base adjustment we have made to Entergy’s SDA cost estimate, 

incorporating the adjustments discussed above.24 

Table 5. Base Adjusted SDA Cost Calculations 

Item Entergy 

EPA 

Adjustments EPA (2013) Comments 

Total Contractor Costs (2010) $156,974,274 $161,676,662 Entergy 2010 cost escalated to 2013 

Contingency (2010) $20,875,711 $21,501,073 EPA escalated to 2013 

BOP (2008) $102,085,500 -$25,866,833 $75,145,724 S&L 2008 BOP minus EPA 

adjustments, then escalated to 2013 

BOP Indirect Costs (2012) $8,733,104 -$8,733,104 $0 Disallowed or undocumented 

Misc Contract Labor (2012) $4,583,719 -$4,583,719 $0 Disallowed or undocumented 

Entergy Internal Costs (2012) $20,076,644 -$20,076,644 $0 Disallowed or undocumented 

Capital suspense (2012) $8,348,276 -$8,348,276 $0 Disallowed or undocumented 

Total Capital Investment (TCI) $258,323,459

Direct Annual Costs (2008) $7,901,369 $7,790,140 EPA escalated to 2013 

Indirect Annual Costs 

 Overhead (2008) $2,572,707 $2,536,491 EPA escalated to 2013 

 Administrative Charges @ 2% of TCI $5,166,469 2% of TCI 

 Property Tax @ 1% of TCI $2,583,235 1% of TCI 

 Insurance @ 1% of TCI $2,583,235 1% of TCI 

Total Indirect Annual Costs $12,869,429

 

22 White Bluff Station Units 1 And 2 Evaluation Of Wet Vs. Dry FGD Technologies, SL-009510, Rev. 3, October 

28, 2008, Project 12303-004, Prepared by Sargent and Lundy. Attached as Attachment D to the 6/10/13 Entergy 

Response to EPA comments on the White Bluff draft BART Report. Table 1-1 

23 See the file, “White Bluff_R6 cost revisions2.xlsx,” tab, ”IPM WB 1 2 lb” in our docket. 

24 See the file, “White Bluff_R6 cost revisions2.xlsx,” tab, ”Entergy Costs” in our docket. 
11 

Although Entergy provides cost estimates for both Units 1 and 2, we note that there is a less than 

1% difference between the two unit costs, and therefore use the adjusted cost for Unit 1 as the 

basis for both units. 

3.1. Entergy’s Coal Sulfur Assumption 

Below is a summary of the annual average monthly SO2 emissions from the White Bluff and 

Independence facilities: 

Table 6. Entergy Annual Average Monthly Emission Rate 

 Annual Average Monthly Emission Rate 

(lbs/MMBtu) 

 White Bluff Independence 

Year Unit 1 Unit 2 Unit 1 Unit 2 

2009 0.597 0.625 0.460 0.470 

2010 0.501 0.513 0.467 0.490 

2011 0.571 0.565 0.529 0.533 

2012 0.597 0.581 0.587 0.580 

2013 0.575 0.572 0.550 0.553 

These units burn subbituminous coal from the Power River Basin of Wyoming with similar 

characteristics. In contrast, presumably for future fuel flexibility, Entergy assumes in its SDA 

cost analysis that it will burn a coal corresponding to an uncontrolled SO2 emission rate of 2.0 

lb/MMBtu – far in excess of the sulfur level of the coals it has historically burned. Thus, 

Entergy has costed SO2 scrubber systems for the White Bluff facility that are overdesigned 

compared to its historical needs. Such a system, being capable of a much higher level of sulfur 

removal than is currently required, has a correspondingly higher cost. This has ramifications for 

the scrubber cost analysis, in which the annualized cost of the controls are compared to the 

projected visibility benefits. This requires that when assessing cost effectiveness either (1) this 

higher cost be balanced against its greater SO2 reduction potential, or (2) that the scrubber 

system’s capability and cost be adjusted down to match the facility’s historical emissions. 

Doing neither, introduces a mismatch between cost and need that skews the cost effectiveness 

calculation. Unfortunately, that is what Entergy has done when it selected its SO2 emission 

baseline by using “the average rate from 2001-2003, as reported by Entergy in their air emission 

inventories,”25 while selecting it annualized costs based on a 2.0 lb/MMBtu coal. 

In calculating baseline emissions, the BART Guidelines assume the source in question is 

otherwise unchanged in the future, except for the addition of BART controls: 26 

The baseline emissions rate should represent a realistic depiction of anticipated 

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

 

25 Revised Bart Five Factor Analysis, White Bluff Steam Electric Station, Redfield, Arkansas (AFIN 35-00110). 

Page 5-5. 

26 70 FR 39167. 
12 

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.

Thus, we believe we must adjust Entergy’s cost effectiveness calculation. Our approach is to use 

our IPM SDA cost model that we reference above, to adjust Entergy’s total annualized cost, and 

then use that adjusted figure when calculating the cost effectiveness. We do this by calculating 

the ratios of the annualized capital costs and operating costs for two SDA cases: a 2.0 lb/MMBtu 

case, and one based on Entergy’s historical SO2 emissions. We then apply these ratios to 

Entergy’s annualized capital costs and the sum of its direct and indirect capital costs. 

3.2. Adjusting Entergy’s SDA Costs for Coal Sulfur Content 

As summarized above, we have run two SDA cost cases, using our IPM SDA cost model for the 

White Bluff Unit 1.27 We have used Entergy’s input variables in both cases,28 except in the 

second case we used a SO2 rate of 0.68 lbs/MMBtu29 in place of Entergy’s assumption of a 2.0 

lb/MMBtu SO2 emission rate. Below is a summary of the input values for the 2.0 lb/MMBtu 

case, the input fields being in yellow: 

 

27 See the file, “White Bluff_R6 cost revisions2.xlsx,” tabs, ”IPM WB 1 2 lb” and “IPM WB 1-0.68 lb” in our 

docket. 

28 White Bluff Station Units 1 And 2, Evaluation Of Wet Vs. Dry FGD Technologies, SL-009510, Rev. 3, October 

28, 2008, Project 12303-004, Prepared by Sargent and Lundy. Attached as Attachment D to the 6/10/13 Entergy 

Response to EPA comments on the White Bluff draft BART Report. .Table 1-1. 

29 Scrubber systems must be designed to treat the maximum sulfur content coal that is anticipated to be burned. Our 

value of 0.68 lb/MMBtu is based on the maximum historical monthly value reported to us by Unit 1 or Unit 2 from 

2009 to 2013. See the file “White Bluff_R6 cost revisions2.xlsx,” tab, “Monthly Emissions” in our docket. 
13 

Table 7. IPM SDA Cost Analysis Using Entergy’s Input Values 

Unit Size (Gross) (MW) 850 

Retrofit Factor 1 

Gross Heat Rate (Btu/kWh) 10,770 Max annual value from 2009-2013 

SO2 Rate (lb/MMBtu) 2.00 Max monthly value from 2009-2013 

Type of Coal PRB 

Coal Factor 1.05 

Heat Rate Factor 1.076998521 

Heat Input (Btu/Hr) 9,154,487,425 

Operating SO2 Removal (%) 95.00 

Assume 95%. If outlet < 0.06 

lbs/MMBtu, then assume % control 

for 0.06 lbs/MMBtu. 

Lime Rate (Ton/Hr) 14 

Waste Rate (Ton/Hr) 30 

Include Aux Power in 

VOM (%) 1.49 Assume aux power is included in VOM 

Makeup Water Rate (1000 gph) 54 

Lime Cost ($/Ton) 107 

Entergy from S&L 2008 Wet FGD vs. 

SDA Cost Analysis 

Waste Disposal Cost ($/Ton) 8.58 

Entergy from S&L 2008 Wet FGD vs. 

SDA Cost Analysis 

Aux Power Cost ($/kWh) 0.047 

Entergy from S&L 2008 Wet FGD vs. 

SDA Cost Analysis 

Makeup Water Cost ($/1000[gal]) 0.92 

Entergy from S&L 2008 Wet FGD vs. 

SDA Cost Analysis 

Operating Labor Rate ($/hr) 40 

Entergy from S&L 2008 Wet FGD vs. 

SDA Cost Analysis 

Elevation adjustment if > 

500 Feet (feet) 0 Default value – check elevation. 

Interest Rate (%) 7 

Equipment Lifetime (years) 30 

Gross Load (MW-hours) 6,275,922 Max annual value from 2009-2013 

SO2 Emission Baseline (tons/year) N/A 

3 –yr avg. 2009-2013, excluding max 

and min 

This cost model was run a second time, with the only change being a 0.68 lb/MMBtu SO2 rate. 

In so doing, we acknowledge that some additional input parameters could change with a switch 

to a coal with a differing sulfur content. However, we do not possess information from Entergy 

that would enable the contrasting the properties of the coals they have burned in the past with the 

hypothetical 2.0 lb/MMBtu coal on which they based the design of their scrubbers. In any case, 
14 

we do not believe any changes would be such that the analysis we do here would be 

fundamentally altered. 

Table 8. Results of IPM SDA Cost Analyses Using Historic vs. Design Coals 

0.68 lb/MMBtu 

Case 

2.0 lb/MMBtu 

Case 

Ratio of 

Selected 0.68 

lb /MMBtu to 

2.0 lb/MMBtu 

Costs 

Capital, engineering and 

construction cost $328,680,000 $342,944,000 0.9584

Capital Recovery factor 0.0806 0.0806

Annualized capital costs $26,487,139 $27,636,624

Variable operating costs $8,581,744 $17,332,840 0.5823 Fixed operating costs $3,812,705 $3,953,100

Total annualized costs $38,881,588 $48,922,564

In the above table, we sum the variable and fixed operating costs for each case in calculating the 

ratios shown. 

4. Calculation of SDA Cost Effectiveness for the White Bluff Facility 

In the table below, we apply the ratios we calculated above to our base adjusted SDA cost 

calculations and then calculate the cost effectiveness for Units 1 and 2. 
15 

Table 9: EPA Calculated SDA Cost Effectiveness for White Bluff Unit 1 

Item 

White Bluff 

Cost at 2.0 

lbs/MMBtu 

Ratio of 0.68 

lb/MMBtu to 

2.0 lb/MMBtu1

Corrected White 

Bluff Cost to 

0.68 lbs/MMBtu 

Annualized Capital Costs $20,817,359 0.9584 $19,951,506

Total Direct and Indirect Annual Costs2 $20,659,569 0.5823 $12,029,724

Total Annualized Cost $31,981,230

Interest Rate (%) 7

Equipment Lifetime (years) 30

Capital Recovery Factor (CRF) 0.0806

SO2 Emission Rate (lbs/MMBtu) 0.65

Controlled SO2 Emission Rate (%) 90.81

SO2 Emission Baseline (tons) 15,816

SO2 Emission Reduction (tons) 14,363

Cost Effectiveness ($/ton) $2,227

Table 10: EPA Calculated SDA Cost Effectiveness for White Bluff Unit 2 

Item 

Corrected White Bluff 

Cost to 0.68 lbs/MMBtu 

Total Annualized Cost $31,981,230 

Interest Rate (%) 7 

Equipment Lifetime (years) 30 

Capital Recovery Factor (CRF) 0.0806 

SO2 Emission Rate (lbs/MMBtu) 0.68 

Controlled SO2 Emission Rate (%) 91.16 

SO2 Emission Baseline (tons) 16,697 

SO2 Emission Reduction (tons) 15,221 

Cost Effectiveness ($/ton) $2,101 

 
16 

4.1. Conservative Aspects of our White Bluff SDA Cost Analysis 

We have adopted conservative assumptions in our analysis of the White Bluff SDA cost analysis, 

which are outlined below: 

 An October, 2008 S&L cost analysis30 assumed a 40 year amortization life. As we note 

in our Oklahoma FIP, 31 we typically assume a 30 year equipment life for scrubbers, as 

we do here. If the service life of SO2 scrubbers installed at the White Bluff facility was 

increased to 40 years, the cost effectiveness would be significantly improved (lower 

$/ton). 

 S&L notes in its 2008 cost analysis32 that an Alstom cost estimate assumed that its SDA 

FGD system is based on the use of three absorber modules. Alstom had proposed two 

modules on units with a similar gas flow in the past, which would result in an 

approximately 7% savings in capital cost. We did not assume this potential cost savings. 

5. Extension of the White Bluff SDA Cost Analysis to the Independence Facility 

The White Bluff and Independence facilities are sister facilities. According to EIA,33 the boilers 

were manufactured by Combustion Engineering with in-service dates of 1980 and 1981 for 

White Bluff, and 1983 and 1985 for Independence. All four units are tangentially firing boilers 

having nameplate capacities of 900 MW and similar gross ratings. As we indicate above, all four 

units burn coal from the Powder River Basin of Wyoming with similar characteristics. All four 

units employ cold side electrostatic precipitators for particulate collection. Other pertinent 

characteristics are similar. The layout of the White Bluff and Independence facilities are also 

very similar as shown by Figures 1 and 2: 

 

 

30 White Bluff Station Units 1 And 2 Evaluation Of Wet Vs. Dry FGD Technologies, SL-009510, Rev. 3, October 

28, 2008, Project 12303-004, Prepared by Sargent and Lundy. Attached as Attachment D to the 6/10/13 Entergy 

Response to EPA comments on the White Bluff draft BART Report. 

31 Response to Technical Comments for Sections E. through H. of the Federal Register Notice for the Oklahoma 

Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA-R06-OAR-2010-0190. Page 

35. 

32 White Bluff Station Units 1 And 2 Evaluation Of Wet Vs. Dry FGD Technologies, SL-009510, Rev. 3, October 

28, 2008, Project 12303-004, Prepared by Sargent and Lundy. Attached as Attachment D to the 6/10/13 Entergy 

Response to EPA comments on the White Bluff draft BART Report. Pdf page 98. 

33 See “EIA Consolidated Data_WB and IND_Y2012.xlsx.” 
17 

Figure 1. Satellite Photograph of the White Bluff Facility 

Figure 2. Satellite Photograph of the Independence Facility 

 
18 

Due to the similarity of these facilities, we apply the total annualized SDA cost we developed for 

the White Bluff units to the Independence units. However, we adjust the cost effectiveness34

($/ton) due to the differing SO2 emissions: 

Table 11: EPA Calculated SDA Cost Effectiveness for Independence Unit 1 

Item 

Corrected White 

Bluff Cost to 

0.68 lbs/MMBtu 

Total Annualized Cost $31,981,230 

Interest Rate (%) 7 

Equipment Lifetime (years) 30 

Capital Recovery Factor (CRF) 0.0806 

SO2 Emission Rate (lbs/MMBtu) 0.63 

Controlled SO2 Emission Rate (%) 90.49 

SO2 Emission Baseline (tons) 14,269 

SO2 Emission Reduction (tons) 12,912 

Cost Effectiveness ($/ton) $2,477 

Table 12: EPA Calculated SDA Cost Effectiveness for Independence Unit 2 

Item 

Corrected White 

Bluff Cost to 

0.68 lbs/MMBtu 

Total Annualized Cost $31,981,230 

Interest Rate (%) 7 

Equipment Lifetime (years) 30 

Capital Recovery Factor (CRF) 0.0806 

SO2 Emission Rate (lbs/MMBtu) 0.61 

Controlled SO2 Emission Rate (%) 90.19 

SO2 Emission Baseline (tons) 15,511 

SO2 Emission Reduction (tons) 13,990 

Cost Effectiveness ($/ton) $2,286 

 

 

34 See the file, “White Bluff_R6 cost revisions2.xlsx,” tab, ”Cost Effectiveness” in our docket. 
19 

6. White Bluff Wet Scrubbing Cost Analysis 

Entergy uses a 2012 S&L wet FGD estimate for the White Bluff Units 1 and 2 as the starting 

point for its cost analysis.35 It then subtracts out all total construction and erection costs from the 

total project costs in order to obtain a total Equipment Cost (EC). Entergy then calculates the 

Purchased Equipment Costs (PEC), using this approximation from our Control Cost Manual36: 

PEC = 1.18 X EC 

Although not stated, Entergy then calculates the Total Capital Investment (TCI) using the 

following approximation from our Control Cost Manual: 

TCI = DC + IC = (1.85 X B) + Site Preparation + Bldg + (0.35 X B) 

Where DC = Direct Costs, IC = Indirect Costs, and B= PEC. It appears Entergy assumed no cost 

for site preparation and buildings. 

Entergy calculated the direct annual costs, using fixed and variable O&M costs from a 2011 S&L 

cost summary as a surrogate for the apparently unavailable direct annual costs from the 2012 

S&L estimate.37 Entergy then calculated the indirect annual costs using multiplier 

approximations from our Control Cost Manual.38 Lastly, Entergy calculated the annualized 

capital cost in the usual manner by multiplying the TCI by the capital recovery factor. 

6.1. Our Critique of the Entergy White Bluff Wet FGD Cost Analysis 

As in its SDA cost analysis, Entergy escalated costs using incorrect CEPCI indices. Entergy also 

assumed it will burn a coal corresponding to an uncontrolled SO2 emission rate of 2.0 lb/MMBtu 

– far in excess of the sulfur level of the coals it has historically burned. As with our SDA cost 

analysis, we address these issues in the same way. Below is a summary of the base adjustment 

we have made to Entergy’s SDA cost estimate, based on the items discussed above.39 

 

35 White Bluff Station Unit 1 & 2, Wet FGD - 2.0 Lb/MMBtu, Order Of Magnitude Cost Estimate Summary. 

Attached as Attachment C to the 6/10/13 Entergy Response to EPA comments on the White Bluff draft BART 

Report. Pdf page 29.Below is 

36 Section 5.2 Post-Combustion Controls, Chapter 1 – Wet Scrubbers for Acid Gas, Table 1.3. 

37 6/10/13 Entergy Response to EPA comments on the White Bluff draft BART Report. Pdf page 11. This 

information was supplemented with a cut sheet from the 2011 S&L report via email from David Triplett on 2-10-15. 

Entergy declined to provide the full report, citing confidentiality concerns. 

38 Section 5.2 Post-Combustion Controls, Chapter 1 – Wet Scrubbers for Acid Gas, Table 1.4. 

39 See the file, “White Bluff wet FGD Costs.xlsx,” tab, ”Entergy Costs” in our docket. 
20 

Table 13. Base Adjusted Wet FGD Cost Calculations 

Item 

Entergy 

Calculation 

Explanation 

Entergy's Cost 

Estimates EPA (2013) EPA Comments 

Capital Costs Unit 1 Unit 1 

Total Equipment Costs (EC) 

(Entergy 2012 Dollars)1 $150,037,000 $145,596,972 Entergy's costs escalated to 2013 

Purchased Equipment Cost (PEC) PEC=1.18 X 

EC as per 

CCM 

$177,043,660 $171,804,428 

Total Capital Investment (TCI) 

$389,496,052 $366,784,526 

As per Table 1.3 of the CCM, 

Entergy calculated TCI = DC + IC 

= (1.85 * PEC) + Site Preparation 

+ Bldg + (0.35 * PEC). Costs 

escalated to 2013. 

Direct Annual Costs (DC) (Entergy 2011 Dollars)2 $15,734,500 $15,240,194 Escalated to 2013 

Overhead (Entergy 2011 

Dollars) 

60% of fixed 

labor and 

material costs 

$2,987,400 $2,893,550 

Escalated to 2013 

Administrative Charges 2% of TCI $7,335,691 

Property Tax 1% of TCI $3,667,845 

Insurance 1% of TCI $3,667,845 

Indirect Annual Costs (IC) $17,564,931 

In order to address the coal sulfur issue, we have run two wet FGD cost cases, using our IPM wet 

FGD cost model for the White Bluff Unit 1.40 We have used Entergy’s input variables in both 

cases41, except in the second case we again used a SO2 rate of 0.68 lbs/MMBtu in place of 

Entergy’s assumption of a 2.0 lb/MMBtu SO2 emission rate. Below is a summary of the input 

values for the 2.0 lb/MMBtu case, the input fields being in yellow: 

 

40 See the file, “White Bluff wet FGD Costs.xlsx,” tabs, ”IPM WB 1 2 lb” and “IPM WB 1-0.68 lb” in our docket. 41 White Bluff Station Units 1 And 2, Evaluation Of Wet Vs. Dry FGD Technologies, SL-009510, Rev. 3, October 

28, 2008, Project 12303-004, Prepared by Sargent and Lundy. Attached as Attachment D to the 6/10/13 Entergy 

Response to EPA comments on the White Bluff draft BART Report. .Table 1-1. 
21 

Table 14. IPM Wet FGD Cost Analysis Using Entergy’s Input Values 

Unit Size (Gross) (MW) 850 

<--- User Input (Greater than 50 

MW) 

Retrofit Factor 1 

<--- User Input (An "average" 

retrofit has a factor =1.0) 

Gross Heat Rate (Btu/kWh) 10,770 <--- User Input 

SO2 Rate (lb/MMBtu) 2.00 

Type of Coal PRB <--- User Input (PRB, BIT, or LIG) 

Coal Factor 1.05 Bit=1, PRB=1.05, Lig=1.07 

Heat Rate Factor 1.076998521 C/10000 

Heat Input (Btu/Hr) 9,154,487,425 A*C*1000 

Operating SO2 Removal (%) 98.00 

<--- User Input (Used to adjust actual 

operating costs) 

Design Limestone Rate (Ton/Hr) 

16 (17.52*A*D*G/2000 (Based on 98% 

SO2 removal) 

Design Waste Rate (Ton/Hr) 

29 

1.811*K (Based on 98% SO2 removal) 

Include Aux Power in 

VOM (%) 

1.62 

(1.05e^(0.155*D+1.3))*F*G 

Makeup Water Rate (1000 gph) 75 (1.674*D+74.68)*A*F*G/1000 

Limestone Cost ($/Ton) 38 <--- User Input 

Waste Disposal Cost ($/Ton) 8.58 <--- User Input 

Aux Power Cost ($/kWh) 0.047 <--- User Input 

Makeup Water Cost ($/1000[gal]) 0.92 <--- User Input 

Operating Labor Rate ($/hr) 40 

<--- User Input (Labor cost including 

all benefits) 

Elevation adjustment if > 

500 Feet (feet) 0 

<--- User Input (no entry needed if 

less than 500 feet) 

Interest Rate (%) 7 <---- User Input 

Equipment Lifetime (years) 30 <---- User Input 

Gross Load (MW-hours) 6,275,922 <---- User Input 

SO2 Emission Baseline (tons/year) N/A <---- User Input 

 
22 

As with our SDA cost analysis, this cost model was run a second time, with the only change 

being a 0.68 lb/MMBtu SO2 rate. Again, we acknowledge that some additional input parameters 

could change with a switch to a coal with a differing sulfur content. However, we do not possess 

information from Entergy that would enable the contrasting the properties of the coals they have 

burned in the past with the hypothetical 2.0 lb/MMBtu coal on which they based the design of 

their scrubbers. In any case, we do not believe any changes would be such that the analysis we 

do here would be fundamentally altered. 

Table 15. Results of IPM Wet FGD Cost Analyses Using Historic vs. Design Coals 

0.68 lb/MMBtu 

Case 

2.0 lb/MMBtu 

Case 

Ratio of 

Selected 0.68 

lb /MMBtu to 

2.0 lb/MMBtu 

Costs 

Capital, engineering and 

construction cost $327,914,000 $350,906,000 0.9345

Capital Recovery factor 0.0806 0.0806

Annualized capital costs $26,425,410 $28,278,253

Variable operating costs $6,457,001 $11,624,809 0.6677 Fixed operating costs $4,383,006 $4,609,278

Total annualized costs $37,265,416 $44,512,339

In the above table, we sum the variable and fixed operating costs for each case in calculating the 

ratios shown. 

7. Calculation of Wet FGD Cost Effectiveness for White Bluff and Independence 

In the table below, we apply the ratios we calculated above to our base adjusted wet FGD cost 

calculations and then calculate the cost effectiveness for the White Bluff and Independence 

facilities. In so doing, we use the same reasoning we used above in calculating the SDA costs: 

the White Bluff and Independence facilities are so similar that wet FGD costs can be applied to 

the Independence units, adjusting the cost effectiveness for differing SO2 baselines. 
23 

Table 16: EPA Calculated Wet FGD Cost Effectiveness for White Bluff Unit 1 

Item 

White Bluff 

Cost at 2.0 

lbs/MMBtu 

Ratio of 

0.68 

lb/MMBtu 

to 2.0 

lb/MMBtu1

Corrected 

White Bluff 

Cost to 0.68 

lbs/MMBtu 

Annualized Capital Costs $29,557,846 0.9345 $27,621,162 

Total Direct and Indirect 

Annual Costs2 $32,805,125 0.6677 $21,905,005 

Total Annualized Cost $49,526,167 

Interest Rate (%) 7 

Equipment Lifetime (years) 30 

Capital Recovery Factor (CRF) 0.0806 

SO2 Emission Rate (lbs/MMBtu) 0.65 

Controlled SO2 Emission Rate (%) 93.87 

SO2 Emission Baseline (tons) 15,816 

SO2 Emission Reduction (tons) 14,847 

Cost Effectiveness ($/ton) $3,336 

Table 17: EPA Calculated Wet FGD Cost Effectiveness for White Bluff Unit 2 

Item 

Corrected 

White Bluff 

Cost to 0.68 

lbs/MMBtu 

Total Annualized Cost $49,526,167 

Interest Rate (%) 7 

Equipment Lifetime (years) 30 

Capital Recovery Factor (CRF) 0.0806 

SO2 Emission Rate (lbs/MMBtu) 0.68 

Controlled SO2 Emission Rate (%) 94.11 

SO2 Emission Baseline (tons) 16,697 

SO2 Emission Reduction (tons) 15,713 

Cost Effectiveness ($/ton) $3,152 

 
24 

Table 18: EPA Calculated Wet FGD Cost Effectiveness for Independence Unit 1 

Item 

Corrected 

White Bluff 

Cost to 0.68 

lbs/MMBtu 

Total Annualized Cost $49,526,167 

Interest Rate (%) 7 

Equipment Lifetime (years) 30 

Capital Recovery Factor (CRF) 0.0806 

SO2 Emission Rate (lbs/MMBtu) 0.63 

Controlled SO2 Emission Rate (%) 93.66 

SO2 Emission Baseline (tons) 14,269 

SO2 Emission Reduction (tons) 13,364 

Cost Effectiveness ($/ton) $3,706 

Table 19: EPA Calculated Wet FGD Cost Effectiveness for Independence Unit 2 

Item 

Corrected 

White Bluff 

Cost to 0.68 

lbs/MMBtu 

Total Annualized Cost $49,526,167 

Interest Rate (%) 7 

Equipment Lifetime (years) 30 

Capital Recovery Factor (CRF) 0.0806 

SO2 Emission Rate (lbs/MMBtu) 0.61 

Controlled SO2 Emission Rate (%) 93.46 

SO2 Emission Baseline (tons) 15,511 

SO2 Emission Reduction (tons) 14,497 

Cost Effectiveness ($/ton) $3,416