### Appendix A.

Technical Support Document

for the

SDA Control Cost Analysis for the Entergy White Bluff and Independence
Facilities Arkansas Regional Haze Fe deral Implementation Plan (SO 2 Cost TSD)

Prepared and Reviewed by:
Joe Kordziii 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 Effectivene ss 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 An alysis 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 Analys es Using Historic vs. Design Coals .......................... 14
Table 9: EPA Calculated SDA Cost E ffectiveness 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 Anal yses 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 .................... 24iii Table 19: EPA Calculated Wet FGD Cost Effectiveness for Independence Unit 2 .................... 24iv 

### 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 Fe deral Implementation Plan

1. Introduction

This TSD describes how we conduc ted control cost analyses for retrofitting certain coal fired EGUs with Spray Dryer Absorbers (SDA, or dr y 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 prov isions of the regional haze ru le for Units 1 and 2 of the Entergy Independence facility.

We have constructed a spreadsheet 1 that contains information concerning ownership, location, boiler type, environmental controls and other information that we draw upon throughout this appendix. This spreadsheet in cludes information contained within EIA Forms 860 and 923. We have also constructed a spreadshee t that contains most of the calcu lations 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 us es 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 estim ated 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 overn ight 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 thei r 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 wh ich future cash flows are translated
into current dollars is calle d present value analysis. When the cash flows involve income and expenses, it is also comm only 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 intere st (discount) rate and then add them together.’’

Our proposed approach is as follows:

 Start with material we and Arkansas recei ved 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 SO 2 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 states 6 that they received two different SDA cost estimate s for white Bluff: an early 2009 Sargent and Lundy (S&L) estimate with a total cont ractor cost of $291,930,000, and a December 2009 estimate from Alstom of $247,856,184. Entergy stat es that unlike the S&L quote, the Alstom estimate was not itemized and only included a tota l price. Entergy uses the 2009 Alstom price quote as the basis for its BART cost analysis for White Bl uff by increasing it by 10%, and scaling the S&L itemized cost to match the 110% ad justed 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 Ente rgy’s determination that considering the coal burned, that a reasonable maximum control leve l 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 stra ight 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 insta llation of two semi-dry SO 2 scrubbing systems, and that it has received cont rol cost analyses from S&L for SDA, wet FGD,
and other controls. It notes th at the “the total contract pri ce for the two semi-dry scrubbing systems included in Alstom’s December 2009 paym ent 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 w ith Alstom in 2010, and that Alstom informed it that if it wanted to continue with the project, that the price would in crease by 10%. Alstom states the resulting cost is $272,197,128. For th e 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 increas e, 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 Al stom 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 schedule 10 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 th at Alstom included in its quote. In the following section, we outline why we believe so me of the work Entergy includes in its
Balance of Plant costs is alrea dy included in the Alstom quote.

We invite Entergy to provide cl arifications 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 quote 12 to supplement its adjusted Alstom quote in its 2013 SDA Cost Analys is. However, it appears that a number of items are either not appropriate for a SO 2 scrubber, or are already cove red 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 equipmen t, lime storage silos, and a railcar unloading shed and dust collection, with a to tal 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 m onth 7. The description states this is a “Lime storage and preparation system.” Since lime is the reag ent for a SDA system, we assume the Alstom quote for a lime storage and preparation syst em 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 th e 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 indi cates 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 ther efore appears to us th at 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 th at booster fans are scheduled to be delivered in month 22, and installed in month 30. Therefore we subtra ct 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 ite ms (Items 301 through 308) that are either calculated as percentages of the equipment, materials, or la bor; 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 Enter gy calculated as being $710,000. Similarly, Item
304.2 covers “Cost Due to Overtime – 5-10s” whic h is not calculated as a percentage of labor, but which obviously is related to the to tal labor needed to install the pertinent equipment. Because as summarized in the ta ble above, we have excluded certain costs from the BOP quote, we believe it is appropriate to adjust the additional BO P costs that are based on those costs. Therefore, we have reduced these costs by the corres ponding percentages we
have calculated in the above tabl e 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:6Table 2. Adjustment to Remaining Entergy BOP Costs1313See “White Bluff_R6 cost revisions2.xlsx,” tab BOPACCT.NO. DESCRIPTIONENTERGYTOTALEQUIPMENTCOSTENTERGYTOTALMATERIALCOSTENTERGYTOTALLABORCOSTENTERGYTOTALCOSTEPATOTALEQUIPMENTCOSTEPATOTALMATERIALCOSTEPATOTALLABORCOSTEPATOTALCOST301 MOBILIZE/DEMOBILIZE@1%OFLABOR301.2 MOBILIZE/DEMOBILIZE@1%OFLABOR $710,000 $710,000 $546,061 $546,061302 COSTDUETOOVERTIME‐5‐10'S302.2 COSTDUETOOVERTIME‐5‐10'S $10,363,000 $10,363,000 $7,970,183 $7,970,183304 PERDIEM‐@$10PERHOUR304.2 PERDIEM‐@$10PERHOUR $10,257,000 $10,257,000 $7,888,659 $7,888,659305 SPAREPARTS@1%OFEQUIPMENT305.2 SPAREPARTS@1%OFEQUIPMENT $476,000 $476,000 $327,060 $327,060306 FREIGHT@5%OFMATERIAL306.4 FREIGHT@5%OFMATERIAL $1,756,000 $1,756,000 $1,413,404 $1,413,404307GENERAL&ADMINISTRATIVE(G&A)@5%OFMATERIALANDLABOR307.5GENERAL&ADMINISTRATIVE(G&A)@5%OFMATERIALANDLABOR $1,756,000 $3,143,000 $4,899,000 $1,413,404 $2,417,281 $3,830,686307.6GENERAL&ADMINISTRATIVE(G&A)@5%OFMATERIALANDLABOR $1,456,000 $1,456,000 $1,119,810 $1,119,810308 PROFIT@10%OFMATERIALANDLABOR308.5 PROFIT@10%OFMATERIALANDLABOR $3,512,000 $6,285,000 $9,797,000 $2,826,809 $4,833,794 $7,660,602308.6 PROFIT@10%OFMATERIALANDLABOR $2,913,000 $2,913,000 $2,240,388 $2,240,388360 NONCONTRACTORINDIRECTS360.8 ENGINEERING‐BOP $9,855,000 $9,855,000 $7,579,481 $7,579,481TOTALSREDUCTIONINBOPCOSTSEPAENTERGY$11,905,667$52,482,000 $40,576,3337 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 reduc tion 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 prop osed by Entergy in its 2013 SDA Cost Analysis, which we believe should not be a part of its S DA 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 SD A quote contains charges for “C apital suspense,” and “Entergy Internal Costs.” Regarding cap ital suspense, Entergy states 14 :

Capital suspense is a distribution of overhead costs associated with administrators, engineers, and supervis ors and includes function specific rates and A&G (Corporate Accounting) rates. Function specific capital suspense is dependent upon the personal hours allocate d 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 ye arly total capital expense budget and the budgete d capital spending for a specific function. Based on Entergy’s experience with hours require d in similar projects, a 2% of total capital has been assumed to represent the future capital suspense of the project.

Regarding “Entergy Internal Cost s,” Entergy states, “Entergy in ternal costs include ESI labor, construction site labor, travel a nd loader costs. No documentati on of these costs was provided. Both of these cost categories include labor, admini strative, and related elemen ts 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 inv ite Entergy to provide clarificat ion. 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 states 15 :

BOP indirect costs are costs associ ated with engineering, construction management, startup and commissioni ng and are estimates provided by the
contractor. Miscellaneous c ontractor labor is inclusiv e of legal support, owner’s insurance, S&L engineering costs, and En tergy’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. Ho wever, the BOP quote discussed above already contains Item 360, entitled “Non Contractor Indi rects,” under which is the subcategory Item 360.8 entitled “Engineering BOP,” for $9,855,000. Fu rthermore, we note that the BOP quote also contains two additional charges for “Gen eral and Administration” (Items 307.5 and 307.6) for a total of $6,355,000. These General and Admi nistrative and Non Co ntractor Indirects categories are broad in scope, unspecific in desc ription, and undocumented. Together, they total $16,210,000. Lacking any documentation to the cont rary, 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 additio nal BOP indirect cost item from the SDA costs.

2.5.3. Miscellaneous Contractor Labor

Entergy includes a cost entitled “Misc C ontractor Labor,” regarding which it notes 16 , “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 dele te 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 i ndirect cost, we assume any work associated with the support or administration of the BO P items are contained w ithin the General and
Administrative and Non Contract or Indirects categories already present in the BOP quote. We therefore propose to delete the Miscellaneous C ontractor Labor cost item from the SDA costs.

2.6. Entergy’s Cost Escalation Methodology

As is usual practice, and in accordance with th e 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 us e of escalation indices by multiplying the older cost by the ratio of the newe r 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 co mposite index, which is constructed from four sub-indices: equipment, construc tion labor, buildings, and engin eering and supervision. Also, the annual composite CEPCI is constructed from the annual average of the monthly composite CEPCI indices, and should be used when escalati ng 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 in dices 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 Ap ril, 2013). We do not be lieve this practice is appropriate, since monthly CEPCI indices can vary qui te a bit with a given year. In any case, it appears that Entergy mistakenly used the January i ndex for each year to re present the entire year. In our SDA cost analysis, we adjust Entergy’ s escalation thro ugh the use of the correct annual CEPCI composite indices.

2.7. Entergy’s Operating and Maintenance Costs

Regarding its operating and maintenance costs (dir ect annual costs), Entergy states, “[t]he O&M cost estimates are based on the Sarg ent & 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 obtaine d 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 disp osal, bag replacement. Entergy also lists the 2012 total indirect cost as being $43,290,224. Subt racting 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 opera ting costs are $16,466,515. Together, these costs are approximately equi valent to what is typically re ferred 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 SO 2 , lime, water, labor, aux. power, waste disposal), 22 results in a
total annual variable and fi xed 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 th at these costs compare favorably with Entergy’s operational and maintenance costs, and therefore accept Entergy’s calculations.

Entergy also calculates property ta x 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 Calcul ations 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 adjust ments 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 revisions 2.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 adju sted 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 SO 2 emissions from the White Bluff and Independence facilities:

Table 6. Entergy Annual Aver age 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 fu ture fuel flexibility, Entergy assumes in its SDA cost analysis that it will burn a coal corresponding to an uncontrolled SO 2 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 SO 2 scrubber systems for the White Blu ff 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 corresp ondingly higher cost. This has ramifications for the scrubber cost analysis, in which the annuali zed cost of the controls are compared to the projected visibility benefits. Th is requires that when assessing co st effectiveness either (1) this higher cost be balanced against its greater SO 2 reduction potential, or (2) that the scrubber system’s capability and cost be adjusted down to match the facil ity’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 SO 2 emission baseline by using “the average rate from 2001-2 003, as reported by Enter gy in their air emission inventories,” 25 while selecting it annualized cost s based on a 2.0 lb/MMBtu coal.

In calculating baseline emissions, the BART Gu idelines assume the source in question is otherwise unchanged in the future, excep t for the addition of BART controls: 26

The baseline emissions rate should repres ent a realistic depiction of anticipated annual emissions for the source. In gene ral, 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. Wh en you project that future operating parameters (e.g., limited hours of operation or capacity utilizati on, 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 en forceable limitations. In the absence of enforceable limitations, you calculate base line 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 tota l annualized cost, and then use that adjusted figure when calculating the cost effectiveness. We do this by calculating the ratios of the annualized capit al costs and operating costs for two SDA cases: a 2.0 lb/MMBtu case, and one based on Entergy’s historical SO 2 emissions. We then apply these ratios to Entergy’s annualized capital cost s 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 SO 2 rate of 0.68 lbs/MMBtu 29 in place of Entergy’s assumption of a 2.0
lb/MMBtu SO 2 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 su lfur content coal that is an ticipated 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

SO 2 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 SO 2 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

SO 2 Emission Baseline (tons/year) N/A 3 –yr avg. 2009-2013, excluding max
and min

This cost model was run a second time, w ith the only change being a 0.68 lb/MMBtu SO 2 rate. In so doing, we acknowledge that some additional input parameters could change with a switch to a coal with a differing sulfur content. Ho wever, we do not possess information from Entergy that would enable the contrasting the properties of the coals they ha ve 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 Anal yses 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 fi xed 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 cal culated 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/MMBtu 1 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 Costs 2 $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

SO 2 Emission Rate (lbs/MMBtu) 0.65

Controlled SO 2 Emission Rate (%) 90.81
SO 2 Emission Baseline (tons) 15,816

SO 2 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

SO 2 Emission Rate (lbs/MMBtu) 0.68

Controlled SO 2 Emission Rate (%) 91.16
SO 2 Emission Baseline (tons) 16,697

SO 2 Emission Reduction (tons) 15,221 Cost Effectiveness ($/ton) $2,10116 4.1. Conservative Aspects of our White Bluff SDA Cost Analysis

We have adopted conservative assumptions in our analysis of the White Bl uff SDA cost analysis,
which are outlined below:

 An October, 2008 S&L cost analysis 30 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 th e service life of SO 2 scrubbers installed at th e White Bluff facility was increased to 40 years, the cost effectivene ss would be significantly improved (lower $/ton).

 S&L notes in its 2008 cost analysis 32 that an Alstom cost estimate assumed that its SDA FGD system is based on the use of three ab sorber 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 ar e sister facilities. According to EIA, 33 the boilers were manufactured by Combustion Engineeri ng with in-service da tes 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 gr oss ratings. As we i ndicate above, all four units burn coal from the Powder River Basin of Wy oming with similar characteristics. All four units employ cold side electrost atic 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 Implemen tation 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 Independe nce Facility18 Due to the similarity of these facilities, we appl y the total annualized SDA cost we developed for the White Bluff units to the Independence units. However, we adjust the cost effectiveness 34 ($/ton) due to the differing SO 2 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 $31,981,230 Interest Rate (%) 7 Equipment Lifetime (years) 30 Capital Recovery Factor (CRF) 0.0806
SO 2 Emission Rate (lbs/MMBtu) 0.63
Controlled SO 2 Emission Rate (%) 90.49
SO 2 Emission Baseline (tons) 14,269
SO 2 Emission Reduction (tons) 12,912 Cost Effectiveness ($/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 $31,981,230 Interest Rate (%) 7 Equipment Lifetime (years) 30 Capital Recovery Factor (CRF) 0.0806
SO 2 Emission Rate (lbs/MMBtu) 0.61
Controlled SO 2 Emission Rate (%) 90.19
SO 2 Emission Baseline (tons) 15,511
SO 2 Emission Reduction (tons) 13,990 Cost Effectiveness ($/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 th e White Bluff Units 1 and 2 as the starting point for its cost analysis. 35 It then subtracts out all total c onstruction 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 Manual 36 :

PEC = 1.18 X EC

Although not stated, Entergy then calculates the Total Capita l 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 appear s Entergy assumed no cost for site preparation and buildings.

Entergy calculated the direct annual costs, using fixed and va riable 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 in direct annual costs using multiplier approximations from our Control Cost Manual. 38 Lastly, Entergy calculated the annualized capital cost in the usual manner by multiplyi ng the TCI by the capital recovery factor.

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

As in its SDA cost analysis, Entergy escalated co sts using incorrect CEPCI indices. Entergy also assumed it will burn a coal corresponding to an uncontrolled SO 2 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 wa y. Below is a summary of the base adjustment we have made to Entergy’s SDA cost es timate, 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 201 1 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.xl sx,” tab, ”Entergy Costs” in our docket.20 Table 13. Base Adjusted We t 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 sulf ur 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

cases 41 , except in the second case we again used a SO 2 rate of 0.68 lbs/MMBtu in place of Entergy’s assumption of a 2.0 lb/MMBtu SO 2 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 Analys is 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

SO 2 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 SO 2 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

SO 2 Emission Baseline (tons/year) N/A <---- User Input22 As with our SDA cost analysis, this cost mode l was run a second time, with the only change being a 0.68 lb/MMBtu SO 2 rate. Again, we acknowledge that some additional input parameters could change with a switch to a coal with a diffe ring sulfur content. However, we do not possess information from Entergy that would enable the c ontrasting the prope rties of the coals they have burned in the past with the hypot hetical 2.0 lb/MMBtu coal on wh ich 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 An alyses 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 fi xed operating costs for each case in calculating the
ratios shown.

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

In the table below, we apply the ratios we calcu lated above to our base adjusted wet FGD cost
calculations and then calculate the cost eff ectiveness for the White Bluff and Independence facilities. In so doing, we use the same reasoni ng 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 SO 2 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/MMBtu 1 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 Costs 2 $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

SO 2 Emission Rate (lbs/MMBtu) 0.65

Controlled SO 2 Emission Rate (%) 93.87

SO 2 Emission Baseline (tons) 15,816

SO 2 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

SO 2 Emission Rate (lbs/MMBtu) 0.68

Controlled SO 2 Emission Rate (%) 94.11

SO 2 Emission Baseline (tons) 16,697

SO 2 Emission Reduction (tons) 15,713 Cost Effectiveness ($/ton) $3,15224 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 $49,526,167 Interest Rate (%) 7 Equipment Lifetime (years) 30 Capital Recovery Factor (CRF) 0.0806
SO 2 Emission Rate (lbs/MMBtu) 0.63
Controlled SO 2 Emission Rate (%) 93.66
SO 2 Emission Baseline (tons) 14,269
SO 2 Emission Reduction (tons) 13,364 Cost Effectiveness ($/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
SO 2 Emission Rate (lbs/MMBtu) 0.61

Controlled SO 2 Emission Rate (%) 93.46
SO 2 Emission Baseline (tons) 15,511

SO 2 Emission Reduction (tons) 14,497 Cost Effectiveness ($/ton) $3,416