November 2010 

Revised BART Cost Effectiveness Analysis 

for Selective Catalytic Reduction 

at the 

Public Service Company of New Mexico 

San Juan Generating Station 

Final Report 

Prepared for 

Ellen Belk 

U.S. Environmental Protection Agency Region 6 

Multi-media Planning and Permitting Division 

1445 Ross Avenue, Suite 1200 

Mail Code: 6 PD 

Dallas, TX 75202-2733 

Prepare by 

Phyllis Fox, Ph.D., PE 

(Consultant) 

RTI Project Number 0209897.004.085 
TABLE OF CONTENTS 

I. INTRODUCTION AND SUMMARY .................................................................... ii

II. COSTING METHOD............................................................................................... 1

III. REVISED COST EFFECTIVENESS ANALYSIS................................................ 3

A. Direct Costs: Purchased Equipment Cost .......................................................... 4 

1. Extrapolation from Saint Johns River Power Park ............................................. 5 

2. Escalation............................................................................................................ 6 

3. Anhydrous Ammonia System............................................................................. 7 

4. Reactor Box, Breeching and Ductwork .............................................................. 7 

5. Expansion Joints................................................................................................. 7 

6. Catalyst ............................................................................................................... 8 

7. Sonic Horns......................................................................................................... 8 

8. Elevator............................................................................................................... 9 

9. Structural Steel.................................................................................................... 9 

10. SCR Bypass .................................................................................................. 10 

11. NOx Monitoring System............................................................................... 10 

12. Auxiliary Electric System Requirements...................................................... 11 

13. Instrumentation and Control System ............................................................ 12 

B. Other Direct Costs.............................................................................................. 12 

1. Air Preheater Modifications.............................................................................. 13 

2. Balanced Draft Conversion............................................................................... 14 

C. Direct Installation Cost....................................................................................... 17 

D. Indirect Costs .................................................................................................. 18 

1. Engineering....................................................................................................... 19 

2. Owners Cost...................................................................................................... 19 

3. Construction Indirects....................................................................................... 20 

4. Contingencies.................................................................................................... 21 

5. Interest During Construction............................................................................. 22 

6. Lost Generation................................................................................................. 22 

E. Fixed Annual Costs............................................................................................. 22 

1. Operating Labor................................................................................................ 22 

2. Maintenance Labor & Materials....................................................................... 23 

F. Variable Annual Costs........................................................................................ 23 

1. Reagent ............................................................................................................. 23 

2. Auxiliary Power Cost........................................................................................ 24 

3. Catalyst Replacement........................................................................................ 25 

G. Capital Recovery............................................................................................. 26 

1. SCR Lifetime .................................................................................................... 27 

2. Interest Rate ...................................................................................................... 27 

H. Other NOx BACT Limits (0.05 Lb/MMBtu Cases)..................................... 28 

I. Cost Summary..................................................................................................... 28 

IV. BART EMISSION RATE ...................................................................................... 30

i
ii

TABLES 

Table 1. Escalation Based on Chemical Engineering Plant Cost Index (CEPCI) ..........6 

FIGURES 

Figure 1. Havana Unit 9 NOx Emissions, lbs/MMBtu, 2007-2010 ........................32 

EXHIBITS 

Exhibit 1. Revised Cost Analyses for SCR at the San Juan Generating Station 
I. INTRODUCTION AND SUMMARY 

 A cost effectiveness analysis evaluates the cost of controlling pollution in dollars 

per ton of pollutant removed. In July 2007, Black & Veatch prepared a cost effectiveness 

analysis for the retrofit of selective catalytic reduction (SCR) onto Public Service 

Company of New Mexico (PNM's) San Juan Generating Station Units 1 - 4 (B&V 

7/11/07 Cost Analysis).1 Subsequently, in October 2010, Black & Veatch updated these 

estimates (B&V 10/22/10 Cost Analysis).2 Both the 2007 and the 2010 cost 

effectiveness estimates significantly overstate the cost of installing SCR at San Juan for

purposes of BART. 

 

 The company's 2010 cost estimates for SCR, ranging from $6,252/ton at Unit 4 to 

$8,378/ton at Unit 2, are much higher than costs estimated at other similar facilities,3

calling the reliability of these estimates into question. I reviewed the Black & Veatch 

analyses and prepared revised cost effectiveness analyses, correcting some of the errors 

that I found. My revisions reduced the cost effectiveness of SCR at San Juan to a range 

of $1,549/ton at Unit 4 to $2,016/ton at Unit 2. Actual cost effectiveness values may be 

lower as at the time of this writing, some cost items were unsupported, preventing a 

comprehensive review. My revised cost analyses are presented in Exhibit 1. 

 Further, the Black & Veatch cost effectiveness analyses were based on an SCR 

assumed to remove only 77% of the NOx, from an inlet of 0.30 lb/MMBtu to 0.07 

lb/MMBtu, based on a 30-day rolling average. However, an emission limit of 0.05 

lb/MMBtu, based on a 30-day rolling average is attainable for the SCR configuration that 

Black & Veatch costed. An SCR designed to meet this limit is more cost effective (i.e., 

the dollars per ton would be lower) as the tons of NOx removed increase more than the 

annual cost. My estimate of the cost effectiveness to reduce NOx at San Juan from 0.30 

lb/MMBtu to 0.05 lb/MMBtu, based on a 30-day rolling average, is included in Exhibit 1 

and ranges from $1,447/ton at Unit 4 to $1,877/ton at Unit 2. 

II. COSTING METHOD 

 Cost effectiveness, measured in dollars per ton of pollutant removed, is calculated 

according to the EPA Air Pollution Control Cost Manual or "Cost Manual",4

 as stipulated 

1

 Black & Veatch, Public Service Company of New Mexico San Juan Generating Station Best Available 

Retrofit Technology Analysis, June 6, 2007 (6/7/07 B&V BART Analysis), as modified by spreadsheets 

captioned "PNM SJGS BART Analysis - Cost Analysis (Draft)," dated 7/11/07 (B&V 7/11/07 Cost 

Analysis). 

2

 Black & Veatch, San Juan Generation Station BART Project Review and Update of 2007 BART Cost 

Estimates, October 22, 2010 (B&V 10/22/10 Cost Analysis). 

3

 Pacificorps Jim Bridger Units 1 - 4: $2,258 - $4,474/ton; Pacificorps Naughton Units 1 - 3 $2,750 - 

$2,830/ton; PGE Boardman: $3,096/ton; Four Corners: $2,515 - $3,163/ton Some of these figures also 

include the installation costs for combustion controls. 

4

 U.S. EPA, EPA Air Pollution Control Cost Manual, Report EPA/452/B-02-001, 6th Ed., January 2002 

("Cost Manual"), The EPA Air Pollution Control Cost Manual is the current name for what was previously 
in the BART Guidelines. A control technology is considered to be “cost effective” if it 

falls within a reasonable range of cost-effectiveness estimates. 

 Cost effectiveness determinations include several steps. First, the capital cost is 

estimated and annualized using a capital recovery factor. Second, the annual operating 

and maintenance (O&M) costs are estimated. Third, these costs are summed and divided 

by the tons of pollutant removed. This calculation requires that the costs for the control 

technology are consistent with the claimed emission reductions. 

 Cost effectiveness is determined by comparing annual cost per ton of pollutant 

removed for the source of interest to the range of cost effectiveness values for other 

similar permit decisions. If a given cost effectiveness value falls within the range of costs 

borne by others, it is per se cost effective unless unusual circumstances exist at the 

source.5

 Thus, cost effectiveness is a relative determination, based on costs borne by 

other similar facilities. To compare costs among units, a level playing field must be 

established by following the same cost rules in each determination.6

 The Black & Veatch 

cost estimating method deviates from the standard procedure developed by EPA used to 

establish the range of acceptable cost effectiveness values. In other words, the Black & 

Veatch cost effectiveness analyses uses a nonstandard cost method and compares the 

results to costs derived using the standard method. 

 In evaluating cost effectiveness, it is important that a consistent set of rules be 

used. Otherwise, one runs the risk of comparing apples with oranges when making the 

cost effectiveness determination. For power plants having a capacity in excess of 750 

MW, as here, Section 169A(b) of the CAA requires that States follow guidelines 

promulgated by EPA for determining BART.7

 The responsive guidelines are contained 

in Appendix Y to Part 51, "Guidelines for BART Determinations Under the Regional 

Haze Rule." These Guidelines include methods to determine both cost and cost 

effectiveness. For cost analyses, the Guidelines stipulate: "In order to maintain and 

 known as the OAQPS Control Cost Manual, the name for the Cost Manual in previous (pre-2002) editions 

of the Cost Manual. 

5

 70 FR 39168 (July 6, 2005). 

6

 See discussion of this issue in Letter from John Bunyak and Sandra V. Silva, Fish & Wildlife Service, to 

Mary Uhl, New Mexico Environmental Department, August 17, 2010, p. 5, footnote 9 ("November 7, 

2007, statement from EPA Region 8 to the North Dakota Department of Health: "...in order to maintain and 

improve consistence, cost estimates should be based on the OAQPS Cost Control Manual. Therefore, these 

analyses should be revised to adhere to the Cost Manual methodology."), p. 6 (quoting a May 10, 2010 

EPA letter to North Dakota Department of Health: "These accounting items [owner's cost] are unauthorized 

under the Cost Control Manual, create an unlevel playing field for comparison with other BACT analyses 

and alone account for an increase in capital costs from the Cost Control Manual by a factor of 1.6."). See 

discussion in: Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry 

O'Clair, Director, Division of Air Quality, North Dakota Department of Health, Re: EPA's Comments on 

the North Dakota Department of Health's April 2010 Draft BACT Determination for NOx for the Milton R. 

Young Station, May 10, 2010, pp. 14-16. 

7

 See, e.g., 70 FR 39158 (July 6, 2005) ("States must follow the guidelines in making BART determinations 

on a source-by-source basis for 750 megawatt (MW) power plants..."). 

2
improve consistency, cost estimates should be based on the OAQPS Cost Control 

Manual, where possible."8

 

 Black & Veatch did not follow these Guidelines and, in fact, argued that they 

were inappropriate.9

 Instead, it used a combination of methods. These methods included 

the use of CUECost, a model that estimates control costs using the levelized cost method 

developed by the Electric Power Research Institute (EPRI), and which is not approved for 

BART determinations; extrapolation from several other projects; and its own proprietary 

databases. 

 However, the purpose of the BART Guidelines is to prepare a regulatory cost 

estimate that allows comparison across multiple units. This estimate is expressed in real 

or constant dollars, less inflation. Consistency among analyses performed across the 

United States is of the essence to establish cost effectiveness. Black & Veatch violated 

these guidelines by including projects that are not required for a retrofit SCR at San Juan 

(SCR bypass, balanced draft conversion); extrapolating costs from unrepresentative 

projects; using contingencies that are excessive for BART determinations; failing to 

optimize costs; double counting costs; annualizing costs using an inflated capital 

recovery factor; including costs for items that are not allowed under the Guidelines; and 

using inflated cost factors, among others. 

 These deviations from standard practice make it appear that the cost to control 

NOx using SCR at San Juan is higher than at other similar sources. However, these 

apparently higher costs are due to the costing method, not to any unique circumstances at 

the units that make the retrofit of SCR unusually costly. The Guidelines require that 

documentation be provided for "any unusual circumstances that exist for the source that 

would lead to cost-effectiveness estimates that would exceed that for recent retrofits."10 

As of the time of this writing, PNM had provided no documentation regarding unique 

circumstances related to the BART determinations. 

III. REVISED COST EFFECTIVENESS ANALYSIS 

 The following sections identify some of the sources of overestimation in the cost 

analysis. My discussion is organized to follow the layout of Black & Veatch's 10/22/10 

cost spreadsheets. The errors that I identify below are incorporated into my revised cost 

analysis in Exhibit 1. 

 

8

 70 FR 39166 (July 6, 2005). 

9

 Black & Veatch, Discussion of OAQPS Cost Manual Method for AQCS Estimation, hereafter referred to 

as “Cost Manual Commentary.” 

http://www.nmenv.state.nm.us/aqb/reghaz/documents/DiscussionofOAQPSCostManualMethodRev080329.

pdf. 

10 70 FR 39168 (July 6, 2005). 

3
A. Direct Costs: Purchased Equipment Cost 

 The direct costs include purchased equipment cost for 13 separate components 

that comprise the SCR: 

• Anhydrous ammonia injection system 

• Anhydrous ammonia vaporization system 

• Reactor box, breeching and ductwork 

• Ductwork expansion joints 

• Catalyst 

• Sonic horns 

• Elevator 

• Structural steel 

• SCR bypass 

• NOx monitoring system 

• Electrical system upgrade 

• Auxiliary electric system requirements 

• Instrumentation and control system 

 The cost for most of these items was scaled from the Saint Johns River Power 

Park11 (SJRPP) project that Black & Veatch had completed the year before they did the 

initial San Juan cost estimate. Cost for some items were also scaled from other 

unidentified projects. Excerpts from the SJRPP vendor quotes are included in Appendix 

C of Black & Veatch's Cost Manual Commentary. The complete vendor quotes were 

separately provided in October 2010 in response to a request by EPA.12 These vendor 

quotes were adjusted by Black & Veatch to 2010 dollars to account for inflation and 

scaled to San Juan using the six-tenth rule where appropriate.13 The methods used are 

outlined in Attachment A to the Cost Manual Commentary, supplemented by responses 

to questions that EPA posed to Black & Veatch,14 These costs were subsequently 

updated by Black & Veatch in the 10/22/10 Revised Cost Analysis.15

 I have made changes in many of these items to adjust them from budgetary quotes 

(used in the 2007 cost analysis) to final contract awards (which are included in Appendix 

 

11 The SJRPP consists of two 670 MW units. The SCR retrofit cost $228 million in 2006 dollars at an 

estimated cost of $170/kW. 

12 Email from Diane Fischer, Black & Veatch, to Joe Kordzi, EPA, October 25, 2010, Re: Quotes from 

SJRPP Project. 

13 The six-tenth rule is used to scale the cost of a process or piece of equipment having one capacity to that 

with another capacity. This rule is explained in Plant Design and Economics for Chemical Engineers, 

Peters, Max, Timmerhaus, Klaus, and West, Ronald, 2003, Fifth Edition. pp. 169-171. 

14 E-mail from Nancy Norem, PNM, to Joe Kordzi, EPA, October 8, 2010, Attached file: "COMPLETE 

100930 EPA Questions on OAQPS.pdf.” 

15 San Juan Generation Station BART Project Review and Update of 2007 BART Cost Estimates, October 

22, 2010 (B&V 10/22/10 Cost Analysis). 

4
A of the Cost Manual Commentary), to exclude equipment and modifications not 

required for the SCR, to correct errors, and to factor out installation, freight, and other 

costs that were included in the contract awards and double counted elsewhere in the 

Black & Veatch cost spreadsheets (Exhibit 1, Fox Rows 15-27). Although not discussed 

below, I note that multiple unit discounts may apply to much of this equipment. 

1. Extrapolation from Saint Johns River Power Park

 The SCR retrofit for SJRPP involved significant challenges due to the range of 

fuels and direct bunkering operations for purposes of blending fuels, which is not 

practiced at San Juan. The SJRPP fuels include a blend of 30% petroleum coke and 70% 

coal, with coke fired for up to 6,000 hours. The coals included a low calcium eastern 

domestic coal and a high silica (erosive) Colombian coal. These three fuels coupled with 

direct bunkering resulted in designs that do not extrapolate to San Juan and in fact 

overestimate San Juan costs when extrapolated from SJRPP.16 The six-tenth rule that 

Black & Veatch used in these extrapolations only applies when the underlying design is 

identical. 

 First, ductwork and ammonia injection grid costs for San Juan are overestimated. 

Petroleum coke firing results in higher flue gas temperatures than coal firing. This 

required material selection based on a design temperature of 824 F and the use of more 

expensive materials of construction for SJRPP: ASTM A588 for ductwork and ASTM 

A335 P11 for the ammonia injection grid. The flue gas temperature for the San Juan 

units ranges from 707 F at Unit 1 to 720 F at Units 3 and 4.17 As discussed below, more 

expensive ductwork materials were used for the SJRPP, based on higher anticipated flue 

gas temperatures than are present at the San Juan. Thus cheaper materials could be used 

for the ammonia injection grid and the ductwork. 

 Second, petroleum coke firing results in high levels of unburned carbon, which 

increases the risk of fires in the ductwork. To avoid fly ash deposition on the ductwork 

floor, the SJRPP ductwork was designed with a high average flue gas velocity, which 

increases the cost of the ductwork, reactor housing, and catalyst compared to the cost of 

comparables at San Juan. As ductwork fires are not an issue at San Juan, an SCR could 

be designed with a lower duct velocity, thus decreasing the cost of most components of 

the SCR. 

 Third, petroleum coke contains high levels of sulfur, up to 6.94%, compared to 

0.77% sulfur in the coal burned at San Juan.18 The high fuel sulfur at SJRPP results in 

corrosive flue gases that form sulfuric acid mist and ammonium bisulfate in the pollution 

control train, requiring more expensive materials of construction. 

 

16 Gerald Smith and others, St. Johns River Power Part 2 x 670 MW SCR - Designed to Ensure Flexibility, 

MEGA 2008. 

17 6/6/07 B&V BART Analysis, p. A-2. 

18 6/6/07 B&V BART Analysis, p. A-2. 

5
2. Escalation

 The B&V 10/22/10 Cost Analysis escalated the original May 2007 costs to 

September 2010 using data for certain materials and equipment from the U.S. Bureau of 

Labor Statistics, confirmed by Black & Veatch's corporate escalation tool.19 While 

escalation to current dollars is a reasonable adjustment, it does not affect the outcome of a 

cost effectiveness analysis because the cost effectiveness of other analyses used to 

establish the acceptable cost range must also be adjusted for escalation. 

 Cost effectiveness analyses for pollution control equipment use the Chemical 

Engineering Plant Cost Index (CEPCI) as published in the journal, Chemical 

Engineering, to escalate costs.20 This index indicates lower escalation than claimed by 

Black & Veatch, as summarized in Table 1. My revised cost analyses are based on 

CEPCI escalation (Exhibit 1, Fox Columns H - I). 

Table 1 

Escalation Based on 

Chemical Engineering Plant Cost Index (CEPCI)21

CEPCI

5/07 

CEPCI

9/10 

Change

CEPCI 

Change 

B&V22

Structural Supports 678.5 679.7 0.2 11.2 

Construction Labor 314.7 328.5 4.4 6.6 

Engineering/Supervision 357.6 338.4 -5.4 NR 

Electrical Equipment 430.6 481.6 11.8 NR 

Other Equipment23 641.6 675.6 5.3 8.4 

Buildings 478.7 506.5 5.8 NR 

 Black & Veatch used 11.2% to escalate materials (reactor box, breeching and 

ductwork, structural steel); 8.4% to escalate equipment (ammonia system, sonic horns, 

electrical system upgrade, etc.); and 6.2% to escalate construction labor and construction 

indirects.24 I revised these choices to use 5.3% for all equipment except electrical; 11.2% 

for electrical equipment; 4.4% for all construction labor and construction indirects, and 

 

19 10/22/10 B&V Cost Analysis, pp. 2-3. 

20 Cost Manual, pdf 665, referred to as “Chemical Engineering Cost Index.” See also: Letter from John 

Bunyak and Sandra V. Silva, Fish & Wildlife Service, to Mary Uhl, New Mexico Environmental 

Department, August 17, 2010, p. 5, footnote 8. 

21 Economic Indicators, Chemical Engineering, August 2008, p. 72 (final CEPCI for May 2007) and 

October 2010, p. 68 (preliminary CEPCI for July 2010). 

22 10/22/10 B&V Cost Analysis, Table 2. 

23 Average of heat exchangers & tanks; process machinery, pipe, valves & fittings, process instruments, and 

pumps & compressors. 

24 10/22/10 B&V Cost Analysis, Tables 7-10, and Exhibit 1, Columns F and G. 

6
no change in materials or engineering/supervision, which the CEPCI indicates declined.25 

As construction labor is not separated from engineering/supervision in the Black & 

Veatch analysis, the use of 4.4% for construction cost items overestimates actual costs as 

the engineering/supervision component has not experienced any escalation. 

3. Anhydrous Ammonia System

 The ammonia system consists of an injection system, a vaporization system, and 

common equipment. The costs for each of these systems at each San Juan unit were 

estimated by dividing the SJRPP budgetary quote lump sum price in half to convert the 

costs to a per-unit basis and in half again to separate out the injection system and the 

vaporization system, adjusted to 2007 dollars using an escalation rate of 1.03.26 This 

estimate was further escalated to 2010 dollars per the Black & Veatch 10/22/10 cost 

analysis. I revised this estimate to use the final contract award cost, reduced to eliminate 

installation ($18,600),27 which is estimated elsewhere (Exhibit 1, Fox Rows 15 and 16). 

4. Reactor Box, Breeching and Ductwork

 The Black & Veatch BART cost was based on a preliminary quote of $5,613,000 

per unit for SJRPP, which was adjusted to account for differences in the size of the San 

Juan units. The final contract price was $4,877,223 per unit.28 Thus, the Black & Veatch 

cost analysis was adjusted to use the final cost. The cost was adjusted to 2007 dollars 

using an escalation rate of 1.03. This estimate was further escalated to 2010 dollars per 

the Black & Veatch 10/22/10 cost analysis. Further, more expensive materials of 

construction were used for SJRPP as maximum flue gas temperatures were higher (>750 

F) than expected at San Juan (<700 F). Black & Veatch estimated that this would reduce 

costs by about 10%.29 These factors have been taken into account in my revised 

estimate (Exhibit 1, Fox Row 17). 

5. Expansion Joints

 The expansion joint cost was scaled from the total cost for both SJRPP units 

($360,430) instead of one unit,30 using the ratio of volumetric gas flow rate in acfm and 

 

25 Exhibit 1, Column H. 

26 Cost Manual Commentary, p. 20. 

27 Cost Manual Commentary, p. 20 and Appendix. C, Secs. 4.1 & 4.2. 

28 Cost Manual Commentary, p. 21. 

29 Email from Norem to Kordzi, October 21, 2010, Re: PNM Responses to Follow-Up Questions from 

October 14, 2010 Conference Call Regarding BART Cost Estimate, October 21, 2010 (10/21/10 

Responses), Response to Question 4, pp. 1-2. 

30 B&V 10/22/10 Cost Analysis, p. 12 ("Correction to the error in expansion joint costs, noted to the EPA 

on October 8, 2010."). 

7
adjusted to 2007, using an escalation rate of 1.03.31 The cost was adjusted to 2007 

dollars using an escalation rate of 1.03. This estimate was further escalated to 2010 

dollars per the Black & Veatch 10/22/10 cost analysis. Further, the vendor quoted price 

includes freight, which is double counted elsewhere in the Black & Veatch cost analysis. 

Finally, the joints are designed for an operating temperature of 800 F with excursions to 

900 F.32 This is far higher than expected at San Juan,33 which could use less expensive 

materials. Thus, I removed the cost of freight ($10,375), reduced the cost of the 

expansion joints by 10% (as with the reactor box, breeching and ductwork, above) to 

account for lower operating temperatures, and used the actual flow rates for each unit34 in 

scaling the costs. These factors have been taken into account in my revised cost estimate 

(Exhibit 1, Fox Row 18). 

6. Catalyst

 The Black & Veatch cost estimates include approximately $2.5 million for Units 

1 and 2 and $3.2 million for Units 3 and 4 for the initial catalyst charge, i.e., filling up the 

reactor. In addition, they include annual charges for replacing catalyst as an operating 

and maintenance (O&M) expense of $426,000 to $541,000 per year35. This double 

counts catalyst cost. The annualized cost of the SCR should be reported “net of the cost 

of replacement materials needed at the beginning of operations” to prevent this double 

counting.36 Thus, I set catalyst cost equal to zero under purchased equipment cost in my 

revised cost estimate (Exhibit 1, Fox Row 19). 

7. Sonic Horns

 The sonic horn cost was estimated from a preliminary quote for SJRPP, adjusted 

to 2007, using an escalation rate of 1.0337 and further escalated to 2010 dollars per the 

Black & Veatch 10/22/10 cost analysis. However, the final contract award was lower. 

Further, the final contract award included freight to the site, which is double counted 

elsewhere in the Black & Veatch cost spreadsheet. Thus, in my revised cost analysis, the 

sonic horn cost is based on final contract award for one unit (Exhibit 1, Fox Row 20). 

The double-counted freight is addressed by subtracting the capital cost of the sonic horns 

from total capital cost before figuring freight (Exhibit 1, Fox Row 30). 

 

31 Cost Manual Commentary, p. 21, Sec. 4.4 and Appx. B, Sec. 4.4, and email from Norem to Kordzi, 

October 8, 2010, Re: Response to Question 7. The volumetric gas flow rates are in the B&V BART 

Analysis, p. A-2, for de-energized hot-side ESP outlet conditions. 

32 Letter from Tom Norwood, Norflex, to JEA Procurement Dept., Re: Invitation for Bids No. SSC-019-07, 

November 24, 2006, Attachment: Expansion Joint Specification Performance Data. 

33 6/6/07 B&V BART Analysis, p. A-3 (De-energized hot-side ESP outlet temperatures range of from 640 - 

698 F). 

34 6/6/07 B&V BART Analysis, p. A-3, De-energized hot-side ESP outlet conditions, volumetric flue gas 

flow rate, acfm. 

35 Cost Manual Commentary, p. 22, Sec. 4.5; B&V lines 19 and 82, respectively of Exhibit 1. 

36 Cost Manual, pdf p.47 and 486 (See Table 2.5, Initial Catalyst and Chemicals, I = 0). 

37 Cost Manual Commentary, p. 22, Sec. 4.6. 

8
8. Elevator

 The elevator cost was estimated from a preliminary quote for SJRPP, adjusted to 

2007, using an escalation rate of 1.0338 and further escalated to 2010 dollars per the 

Black & Veatch 10/22/10 cost analysis. However, the final contract award was lower. 

Further, the final contract award includes installation, which is broken out separately on 

the bid form, as well as freight and taxes.39 Installation, freight, and taxes are calculated 

elsewhere in the Black & Veatch cost spreadsheet and thus are double counted. 

 In my revised cost analysis, elevator cost is based on final contract award, 

adjusted to 2007 dollars (1.03), and to eliminate installation cost (Exhibit 1, Fox Row 

21).40 The double-counted taxes are addressed by subtracting the capital cost of the 

elevator from total capital cost before figuring tax (Exhibit 1, Fox Row 29). The doublecounted freight is addressed by subtracting the capital cost of the elevator from total 

capital cost before figuring freight (Exhibit 1, Fox Row 30). 

9. Structural Steel

 The structural steel cost was estimated from a budgetary quote for SJRPP, 

adjusted to 2007, using an escalation rate of 1.03, and a "complexity factor." This 

estimate was further escalated to 2010 dollars per the Black and Veatch 10/22/10 cost 

analysis. The complexity factor is a contingency for site congestion that has been double 

counted in a contingency figured as 20% total direct costs, as discussed below in Section 

III.D.4. Thus, the complexity factor was eliminated and the cost recalculated using the 

final contract award.41 Further, inspection of Google Earth images of San Juan and 

SJRPP suggests that San Juan is not more congested than SJRR. Finally, the Black & 

Veatch structural steel cost includes freight to the jobsite, which is included elsewhere. 

This double-counted freight is addressed by subtracting the capital cost of structural steel 

from total capital cost before figuring freight (Exhibit 1, Fox Row 30). 

 Even with these adjustments, structural steel costs are overestimated, as the 

contract award amount used to make these extrapolations included "all associated 

engineering and design costs, procurement, fabrication, overtime, overhead, profit markup and shipping to the jobsite." Further, the structural steel was to be delivered painted.42 

These costs are double counted elsewhere, as discussed below. 

 

38 Cost Manual Commentary, p. 23, Sec. 4.7. 

39 Cost Manual Commentary, Appendix. B; Appendix C, Sec. 4.7; and Letter from Paul Starstrom, Kone, 

Inc. Re: SJRPP NOx Reduction Project, December 12, 2006 ("Our pricing includes all applicable 

taxes...We have figured for 50% of the installation to occur in 2008."). 

40 Vendor quote = $583,720 (elevator) + $374,220 (installation) = $957,940. 

41 Cost Manual Commentary, p. 25, Sec. 4.9: Structural Steel, and email from Norem to Kordzi, October 8, 

2010, Response to Question 11. 

42 Cost Manual Commentary, Appx. C, Sec. 4.9: Structural Steel. 

9
10. SCR Bypass

 The SCR bypass cost was estimated from a budgetary quote for SJRPP, adjusted 

to 2007, using an escalation rate of 1.03, and a "complexity factor." This estimate was 

further escalated to 2010 dollars per the Black & Veatch 10/22/10 cost analysis. This 

results in a cost of $10 million per unit for an SCR bypass to route flue gas around the 

catalyst during startup. This is claimed to be required to prevent catalyst fouling when 

firing oil during startup.43 However, fouling would only occur if the oil is not burned and 

thus coats the catalyst. This could only occur due to poor combustion. Oil is very 

efficiently burned in modern low NOx burners with oil igniters, such as those on the San 

Juan units, which were installed between 2007 and 2010. If these burners are properly 

maintained and operated, fouling during startup will not occur. 

 Catalyst can be designed to avoid oil startup issues.44 The Mirant Unit 1 & 2 

SCR system at the Morgantown Station is designed to remove 92.5% of the NOx, to an 

outlet of 0.045 lb/MMBtu, for year round operation with no SCR bypass during startup 

when the plant fired fuel oil and for No. 6 oil during cofiring.45 Similarly, Duke Ene

Belews Creek Steam Station, for example, has operated two 1200-MW bituminous coalfired boilers with SCR since 2004, with oil startup and no catalyst bypass.

rgy's 

46 Further, 

there are oil-fired boilers and turbines equipped with SCR that operate without bypasses. 

Thus, I set the SCR bypass cost equal to zero in my revised cost estimate (Exhibit 1, Fox 

Row 23). 

11. NOx Monitoring System

 The NOx Monitoring cost was estimated from a preliminary quote for SJRPP, 

adjusted to 2007, using an escalation rate of 1.03 and further escalated to 2010 dollars per 

the Black & Veatch 10/22/10 cost analysis.47 However, the final contract award was 

lower. The final contract award included freight to the site, on-site training for each of 

two units, and a 3-year maintenance contract.48 Freight and maintenance are double 

 

43 PNM Response to BART Analysis Questions from NMED, September 14, 2007. 

44 Clayton A. Erickson and others, Design, Installation and Startup Experience on a High Removal 

Efficiency SCR System, Available at: http://secure.awma.org/presentations/Mega08/Papers/a108_1.pdf. 

45 Clayton A. Erickson and others, Design, Installation and Startup Experience on a High Removal 

Efficiency SCR System, p. 7, and Arthur Kohl and Richard Nielsen, Gas Purification, 5th Ed., Gulf 

Publishing Company, 1997, p. 921, and S.M. Cho and S.Z. Dubow, Design of a Selective Catalytic 

Reduction System for NOx Abatement in a Coal-Fired Cogeneration Plant, Proceedings of the American 

Power Conference, April 13-15, 1992, pp. 717-722. 

46 The design of the Belews Creek SCR, including no bypass, is described in: W. Wayne Whitaker and 

others, Successful Year-Round SCR Operation at Duke Energy's Belews Creek Power Plant, PowerGen, 

November 2006. EIA-923, Schedule 3A indicates the only startup fuel is distillate fuel oil. See: 

http://www.eia.doe.gov/cneaf/electricity/page/eia906_920.html. 

47 Cost Manual Commentary, p. 26, Sec. 4.10. 

48 Bid Form, Alltech Environment USA Corp., pdf 2-3 (Unit 1 & 2 technical assistance = $7,349, on-site 

training = $6,101, 3-yr maintenance contract = $132,000). 

10
counted as they are included elsewhere. Further, only a single training session is required 

for all four San Juan units, not a separate training session for each unit, as estimated by 

Black & Veatch. 

 Thus, in my revised cost analysis, the NOx monitoring system cost is based on 

final contract award, adjusted to require only one training session for the station and to 

remove the maintenance contract, adjusted to 2010 dollars (Exhibit 1, Fox Row 24). The 

double-counted freight is addressed by subtracting the capital cost of the system from 

total capital cost before figuring freight (Exhibit 1, Fox Row 30). 

12. Auxiliary Electric System Requirements

 

 In the October 22, 2010 revision to its cost analysis, Black & Veatch added a new 

cost item, "auxiliary electric system requirements," amounting to $6,400,000 for each of 

Units 1 and 2 and $8,350,000 for each of Units 3 and 4.49 These additions are based on 

"minimum" load changes due to the SCR totaling 26,254 kW. These increased loads are 

met by replacing existing fans with larger fans and include flow margins of 15% to 20% 

and pressure margins of 35% to 45%.50 

 The auxiliary power upgrade is required due to the cumulative effect of the 

Consent Decree projects and the SCR and benefits the entire fan auxiliary system. The 

SCR project was initially evaluated at the same time that the Consent Decree projects 

were being designed. Black & Veatch states: "In the initial 2007 estimate, PNM 

expected the existing auxiliary power to be sufficient. However, now that the consent 

decree AQC equipment has been installed, B&V has determined that the current auxiliary 

power system is not sufficient to power the additional loads that would result from adding 

SCR and associated equipment."51 

 Further, the auxiliary power upgrades cumulatively serve the increase in auxiliary 

power. The modifications, for example, include new transformers, switchgear, and motor 

control centers that will serve the entire fan auxiliary loads of both the Consent Decree 

projects and the SCR.52 Thus, these costs should be prorated, rather than partitioned to 

the last project built. 

 I prorated the costs based on the SCR's contribution to draft pressure loss through 

the exhaust system. The draft system pressure curves in Appendix B of the 10/22/10 

Cost Analysis indicate that the SCRs would increase the draft pressure by 10 inches of 

water gauge (in. w.g.) at all units. For Units 1 and 2, the drop in pressure from the forced 

draft fan outlet (#2: 22 in w.g.) to the inlet of the induced draft booster fan (#12: -21 in. 

 

49 B&V 10/22/10 Cost Analysis, Sec. 3.0, pp. 3-5. 

50 Email from Norem to Kordzi, November 4, 2010, Re: Questions on PNM's Revised Cost Estimate for the 

SJGS SCR Project, Response to Question 3. 

51 B&V 10/22/10 Cost Analysis, pp. 3-6. 

52 B&V 10/22/10 Cost Analysis, Sec. 3.0 and email from Norem to Kordzi, November 4, 2010, Re: 

Questions on PNM's Revised Cost Estimate for the SJGS SCR Project, Response to Question 3, Table 3. 

11
w.g.) is 43 inches for the pressurized furnace with SCR. Thus, the SCR is responsible for 

only 23% of the total draft pressure (10/43). For Units 2 and 3, the drop in pressure from 

the forced draft fan outlet (30 in. w.g.) to the inlet of the induced draft booster fan (-26 in. 

w.g.) is 56 inches for the pressurized furnace with SCR. Thus, the SCR is responsible for 

only 18% of the total draft pressure (10/56). Thus, in my revised cost analysis, I prorated 

the cost of the auxiliary power upgrade according to the fraction of the increase in draft 

pressure due to the SCR, or 10 inches of water (Exhibit 1, Fox Row 26). The SCR draft 

lost of 10 in w.g. is high and should be reviewed. 

13. Instrumentation and Control System

 The instrumentation and control system cost was estimated from a preliminary 

quote for SJRPP, adjusted to 2007 using an escalation rate of 1.03 and further escalated 

to 2010 dollars per the Black & Veatch 10/22/10 cost analysis.53 However, the final 

contract awards were higher. They consist of the sum of bids from two separate 

contractors. In each case, the quotes include freight to the site and installation, both of 

which are double counted elsewhere. Further, one year of escalation (1.03) is not 

warranted as the final quotes are dated December 8, 2006 and April 5, 2007. The cost 

analysis was prepared in the first quarter of 2007 and dated May 2007. 

 Thus, my revised cost analysis is based on the final contract awards with no 

escalation to 2007 (Exhibit 1, Fox Row 27), adjusted to 2010 dollars. The doublecounted freight is addressed by subtracting the capital cost of the instrumentation and 

control system from total capital cost before figuring freight (Exhibit 1, Fox Row 30). 

The double-counted installation cost is addressed by subtracting the capital cost of the 

instrumentation and control system from the total purchased equipment cost (Exhibit 1, 

Fox Row 42). 

B. Other Direct Costs 

 Direct costs also include certain other costs that are figured after taxes, freight, 

and installation, suggesting they are quoted installed (Exhibit 1, Rows 44-48). These 

include: 

• Air preheater modifications 

• Balanced draft conversion 

• Site preparation 

• Buildings and enclosures 

These are discussed below. 

 

53 Cost Manual Commentary, p. 27, Sec. 4.12. 

12
1. Air Preheater Modifications

 The 2007 cost estimate included $1,071,000 to modify each of the air preheaters 

at Units 1 and 2 and $8,685,000 to modify each of the air preheaters at Units 3 and 454. 

In response to an EPA comment, Black & Veatch modified the Units 3 and 4 estimate to 

eliminate double counting, revising the cost for Units 3 and 4 to $5,090,000 each.55 

These figures were further escalated to 2010 dollars in the Black & Veatch 10/22/10 cost 

analysis. These estimates were variously claimed to be based on "the experience of a 

confidential client"56 and a "quote for SJGS" and "scaled from another project."57 Black 

& Veatch declined to share the basis for these costs with EPA. 

 The modifications are not required for a properly designed SCR on a boiler that 

burns low sulfur coal. Black & Veatch asserts the upgrades are required to make the air 

preheaters resistant to ammonium bisulfate corrosion and plugging.58 Air preheater 

modifications are required for units that burn high sulfur coal.59 However, San Juan 

burns a low sulfur coal containing only 0.77% sulfur.60 These lower sulfur coals 

generate very little sulfur trioxide61 and thus little ammonium bisulfate corrosion and 

plugging. Air heater plugging is not an issue for these coals if the SCR is designed with a

low SO2 to SO3 catalyst and an ammonia slip of 2 ppm. These are both proposed for the 

San Juan SCR. Thus, air preheater modifications are not required for the San Juan SC

See discussion of this issue by Sargent & Lundy for a similar facility burning a similar 

coal in a BART analysis for the Navajo Generating Sta 62

R. 

tion.

 

54 6/6/07 B&V BART Analysis, p. C-13 to C-16, inclusive. 

55 B&W 10/22/10 Cost Analysis, p. 12 and Tables 7-10. 

56 Email from Norem to Kordzi, September 27, 2010, Re: SJGS BART, Attachment: PNM BART Notes Re 

Response to EPA Fox 22 Questions 92710.DOC, Response to Question 10. 

57 Email from Norem to Kordzi, November 4, 2010, Re: Additional Questions on PNM's Revised Cost 

Estimate for the SJGS SCR Project, Response to Question 2. 

58 Cost Manual Commentary, pp. 10, 28. 

59 Louis P. Bondurant III, SCR Compatibility for the Ljunstrom Air Preheater, available here: 

http://www.airpreheatercompany.com/Data/DownloadDocuments/Mega%20Symposium%201999.PDF 

60 6/6/07 B&V BART Analysis, p. A-2; Email from Norem to Kordzi, 10/21/10, “PNM Responses to 

Follow-Up Questions from October 14, 2010 Conference Call Regarding BART Cost Estimate,” 

Attachment 2, pdf 10. 

61 Email from Norem to Kordzi, 10/8/10, “PNM Response to EPA Question from Joe Kordzi, via email, 

dated September 29, 2010,” Air Pollution Testing, Inc., Source Emissions Testing Report for Public 

Service New Mexico: San Juan Generating Facility, Units 1 and 3, SO3/H2SO4 Emissions, March 11, 

2009. See also sulfuric acid mist test conducted at Navajo Generating Station Units 1-3, which burns a 

very similar coal (finding 0.0000175 to 0.000164 lb/MMBtu of sulfuric acid mist): Catalyst Air 

Management, Inc., Salt River Project Navajo Generating Station Units 1, 2 & 3, Acid Mist Emissions Test 

Report, December 31, 2009, Table 1. 

62 Sargent & Lundy, Salt River Project Navajo Generating Station - Units 1, 2, 3, SCR and Baghouse 

Capital Cost Estimate Report, Revision D, August 17, 2010, Sec. 3.5.5.2, pp. 3-5 to 3-7. 

13
 Further, support for the cost estimates is not in the record as of this writing, 

though it has been requested. The design and condition of San Juan's air preheaters and 

proposed modifications are unknown. These air preheaters, for example, may be at the 

end of their useful life or otherwise require upgrading, independent of the SCR. Further, 

it is unknown whether the costs are for replacing all air heater baskets or just the cold end 

baskets. Thus, I have eliminated the cost of air preheater modifications, pending 

compelling justification that they are required for the SCR. (Exhibit 1, Fox Row 44). 

2. Balanced Draft Conversion

The revised Black & Veatch costs include $14.3 million at each of Units 1 and 2 

and $18.7 million at each of Units 3 and 4 for balanced draft conversions.63 These 

figures were further escalated to 2010 dollars in the Black & Veatch 10/22/10 cost 

analysis. The majority of these costs, 70%+, is due to stiffening of the boiler, air heater, 

electrostatic precipitator, and fabric filter to comply with code. The balance of the costs 

are for induced draft fans to support the increased draft from the SCR and new motors for 

existing forced draft fans. Although increased draft is needed to support an SCR, which 

would be delivered by the induced draft fans, a balanced draft conversion with the 

proposed stiffening is not part of an SCR project. 

Combustion air must be drawn into the boiler and combustion gases must be 

sucked out of the boiler, through the ducts and pollution control trains and up the stack. 

Historically, this was done using a fan at the inlet of the boiler system (a forced draft or 

FD fan). The FD fan pumps air at a pressure high enough to overcome the resistance of 

the duct system. This forces air and flue gases through the system and out the stack. 

Forcing air into the boiler with forced draft fans creates pressures above atmospheric in 

the boiler, hence the name, "pressurized draft." 

This not only pushes gases through the system and out the stack, but also through 

any penetrations and seals and into the boiler penthouse and ambient air. These systems 

have typically deteriorated with age, resulting in ash-laden flue gases and coal particles 

escaping from the boiler, flues, ducts, and other equipment. This leakage poses various 

maintenance, cleanliness, and safety issues. Thus, this design is no longer used and 

existing pressurized system are being converted to balanced draft, which have 

significantly less ash and soot leakage around the boiler working area and experience 

higher availability.64 

Aging pressurized boilers can be converted to “balanced draft,” which uses a 

forced draft fan to push air into the boiler and an induced draft fan on the other end of the 

furnace to suck combustion gases out of the boiler, through and out the stack. The two 

fans maintain the pressure of the boiler in balance, generally 0.08 - 0.1 inches of water 

below atmospheric pressure at the boiler exit. This prevents harmful gases and particles 

 

63 B&V 10/22/10 Cost Analysis, Sec. 4.0, pp. 6-12. 

64 6/6/07 B&V BART Analysis, p. 3-24 and P. Basu, C. Kefa, and L. Jestin, Boilers and Burners, Design 

and Theory, Springer, 2000, pp. 458-459. 

14
from escaping from the boiler and downstream equipment, reducing maintenance, 

increasing availability, and improving safety. Thus, conversion is desirable, but not 

required for an SCR. 

The addition of environmental control systems downstream from the boiler, such 

as the baghouses installed under the Consent Decree or the proposed SCR, raises total 

system resistance, requiring higher pressures, which could cause higher flue gas and fly 

ash leakage from the boiler. This is avoided by using an induced draft (ID) fan prior to 

the stack to draw air and flue gases through the system. 

The Consent Decree projects added new induced draft fans between the 

pressurized boiler and the stack.65 The resulting systems, pressurized boilers with 

downstream induced draft fans, are neither true pressurized system nor pure balanced 

draft systems but rather hybrids.66 Black & Veatch uses this ambiguity to argue that at 

the time of the Consent Decree, stiffening was not required as NFPA 8567 (2004 revision) 

did not apply to hybrid systems which were neither "truly forced draft or truly balanced 

draft."68 By 2007, Black & Veatch argue NFPA 85 (2007 revision) had changed to 

require stiffening of hybrid systems.69 Thus, they attribute 100% of the stiffening cost 

and lost generation due to an extended outage to the SCR alone.70 The sections of NFPA 

85 that Black & Veatch rely on in reaching these conclusion are: 

NFPA 85 (2004 Revision) 

4.6.1 Structural Design. The furnace shall be capable of withstanding a 

transient design pressure without permanent deformation due to yield or buckling 

of any support member. 

 4.6.1.1 Positive Transient Design Pressure. For all boilers other than 

fluidized-bed boilers, the positive transient design pressure shall be at least, but 

shall not be required to exceed, +8.7 kPa (+35 in. of water). 

 4.6.1.2. Negative Transient Design Pressure.

 4.6.1.2.1 The negative transient design pressure shall be at least as 

 negative as, but shall not be required to be more negative than, -8.7 kPa (-35 in. of 

 water). 

 

65 B&V 10/22/10 Cost Analysis, p. 6 and Appx. B. 

66 Email from Norem to Kordzi, October 19, 2010, Re: NFPA Manual. 

67 National Fire Protection Association (NFPA) Code 85, Boiler and Combustion Systems Hazards Code 

(NFPA 85). 

68 6/7/07 B&V BART Analysis, p. 4-6. 

69 B&V 10/22/10 Cost Analysis, Sec. 4.0. 

70 B&V 10/22/10 Cost Analysis, Sec. 4.0, pp. 6 - 12. 

15
NFPA 85 (2007 Revision)

 4.6.1 The furnace shall be capable of withstanding transient design 

 pressures and normal operating pressure without permanent deformation due to 

 yield or buckling of any support member. Transient pressures to be considered 

 shall include but shall not necessarily be limited to misoperation of fans or 

 dampers and a master fuel trip while operating at maximum design load. Refer to 

 individual chapters for additional guidance. 

 6.5.1.3: Balanced Draft Units. All boilers with a fan located in the flue 

 gas path downstream of the boiler enclosure shall be designed in accordance with 

 either 6.5.1.3.1 or 6.5.1.3.2. 

 6.5.1.3.1 The furnace and flue gas removal system shall be designed so 

 that the maximum head capability of the induced draft fan system with ambient 

 air does not exceed the continuous design pressure of furnace, ducts, and 

 associated equipment. 

 6.5.1.3.2 Where a furnace pressure control system in accordance with 

 6.5.2 is provided, the furnace shall be designed for the transient design pressures 

 in 6.5.1.3.2.1 and 6.5.1.3.2.2. 

 My review of the 2004 and 2007 revisions of NFPA 85 indicates that the 2004 

revision of the cited provisions applied to the Consent Decree projects. Thus, costs 

should be prorated among the Consent Decree projects and the SCR installations. There 

are two applicable code sections: (1) general structural design requirements and (2) 

specific transient design pressure limits. 

 The general structural design requirements in Section 4.6.1 apply to all types of 

boilers in both the 2004 and 2007 revisions. This section requires that the "furnace" be 

capable of withstanding a transient design pressure without permanent deformation due 

to yield or buckling of any support member.71 Furnace is unambiguous. Pressurized and 

balanced draft systems contain furnaces. 

 The specific transient design pressure limit of +/-35 inches applied to all boilers 

under the 2004 revision and just balanced draft boilers in the 2007 revisions. In the 2004 

revision, subsections 4.6.1.1 and 4.6.1.2 set maximum transient design pressures for all 

boilers except fluidized-bed boilers for positive pressure and all boilers for negative 

pressure (as no qualifier is indicated). This included the San Juan units at the time of the 

Consent Decree, which were converted to positive pressure furnaces with a fan between 

the furnace and the stack. There is no hint of an exclusion for positive pressure furnaces 

with a fan between the furnace and the stack in the 2004 revision. 

 The 2007 revision modifies the sections dealing with specific design pressures, 

but not unambiguously so. The 2007 revision attempts to clarify this by excluding 

 

71 The general structural design requirement in Section 4.6.1 of both the 2004 and 2007 revisions states 

"furnace." Thus, the general structural design requirements in 2004 and 2007 applied to all boilers. 

16
pressurized units without a fan in the flue gas path (Sec. 6.5.1.2) and defining balanced 

draft units to be all boilers with a fan located in the flue gas path, downstream of the 

boilers (Sec. 6.5.1.3). However, the 2007 revision is still ambiguous. Section 6.5.1.3, 

captioned "balanced draft units," states: "All boilers with a fan located in the flue gas path 

downstream of the boiler enclosure shall be designed in accordance with either 6.5.1.3.1 

or 6.5.1.3.2." This statement is in a section captioned "balanced draft units," which is not 

defined in the code. Thus, it could be interpreted as not applying to the pressurized units 

at San Juan, which are not balanced draft units. Under this interpretation, the SCR would 

not trigger stiffening unless the boilers were first converted to true balanced draft 

operation. As balanced draft conversion is not required for an SCR, under this 

interpretation, stiffening would not be required. 

In sum, stiffening was triggered by the Consent Decree projects, based on the 

plain language of NFPA 85. Thus, none of the stiffening costs should be attributed after 

the fact to the SCR. Further, as the 2007 code is ambiguous, an argument could be made 

that NFPA 85 does not apply to the hybrid San Juan boilers. As noted previously, the 

SCR accounts for only 23% of the pressure drop at Units 1 and 2 and 18% at Units 3 and 

4 along the flue gas path. Thus, even assuming stiffening were triggered by the addition 

of the SCR, at most, only a prorata share of the cost should be charged to the SCR. Thus, 

in my revised cost analysis, I separated the cost of stiffening from the cost of balanced 

draft conversion. For stiffening, I prorated the cost according to the SCR's contribution 

to drop in draft pressure (Exhibit 1, Fox Row 45). 

Balanced draft conversion, on the other hand, while good engineering design, is 

not required for an SCR regardless of code interpretation. Thus, I eliminated the cost of 

the fan modifications required to convert to balanced draft operation (Exhibit 1, Fox Row 

45),72 but retained the fan modifications which are required to supply increased auxiliary 

power due to the SCR (Exhibit 1, Fox Row 46). 

C. Direct Installation Cost 

 The direct installation cost consists of individual cost estimates for 8 separate 

components: 

• Foundation & supports (30%) 

• Handling & erection (30% on Units 1, 2, and 4; 40% on Unit 3) 

• Electrical (15%) 

• Piping (2.5%) 

• Insulation (10%) 

• Painting (1%) 

• Demolition (10%) 

• Relocation (5%) 

 

72 B&V 10/22/10 Cost Analysis, Tables 4 & 5, column "pressurized furnace differential." 

17
 The costs of these items were estimated by Black & Veatch by factoring the costs 

from total purchased equipment costs (PEC) using the percents following each item. The 

factors used to estimate these costs are much higher than the defaults used in the Cost 

Manual. The sum of the factors used by Black & Veatch equals 103.5% for Units 1, 2, 

and 4 and 113.5% for Unit 3. In other words, these direct installation costs more than 

double the purchased equipment costs. 

 These are standard cost categories included in the Cost Manual for many pollution 

control technologies. These costs are also identified as valid cost items for SCR. 

However, the Cost Manual does not provide factors to estimate them for SCR.73 The 

sum of these factors used in the Cost Manual for other pollution control technologies 

ranges from 30% for catalytic absorbers and carbon absorbers to 85% for gas absorbers. 

 

 The factors used for San Juan are unsupported in the record, even though New 

Mexico specifically requested support. The factors are demonstrably high. An SCR is a 

metal frame stuffed with blocks of catalyst. It has no moving parts. Painting, for 

example, is minimal as most items arrive at the site primed; structural steel arrives at the 

site painted. In fact, Black & Veatch zeroed out both painting and insulation in its 

calculation of construction indirects but failed to carry this over to direct installation 

costs.74 Foundation and supports, costed as 30% of purchased equipment cost, are two to 

three times higher than upper bound costs reported by others for similar sized units75

($8/MW compared with $18/MW to $29/MW for San Juan). 

 As the San Juan direct installation cost factors are high compared to similar 

estimates in other BART analyses and high compared to actual costs that I have 

reviewed, I have adjusted them downward as a lump sum based on the median (62%) of 

the lump sum range of 30% to 85% from the Cost Manual. Thus, rather than adjust each 

of these items, I calculated the total direct installation costs as 62% of the total purchased 

equipment cost (Exhibit 1, Fox Row 42). 

D. Indirect Costs 

 The indirect costs consist of individual cost estimates for nine separate 

components: 

• Engineering (7%) 

• Owner's cost (5%) 

• Construction management (10%) 

• Construction indirect 

• Startup and spare parts (3%) 

73 Cost Manual, pdf 483. 

74 Email from Norem to Kordzi, October 18, 2010, Re: Questions on the Cost of Materials and Labor and 

Cost Manual Commentary, p.30. 

75 LG&E Energy and Babcock Power, Selective Catalytic Reduction: From Planning to Operation, 

PowerGen 2005. 

18
• Performance test 

• Contingencies (20%) 

• Interest during construction 

• Lost generation 

 The costs for several of these items were estimated by Black & Veatch by 

factoring the costs from direct costs (DC) using the percents following each item. Black 

& Veatch's indirect costs are high. They amount to 69% to 74% of the total direct costs. 

In contrast, the indirect costs were only 55% of the total direct costs for SJRPP, which 

was used as the basis of the San Juan costs.76 

 The Cost Manual reports indirect costs as a percent of purchased equipment cost 

or PEC. The total indirect costs in the Cost Manual range from 31% of PEC for a carbon 

absorber or condenser to 57% of PEC for an electrostatic precipitator.77 The Black & 

Veatch indirect costs, when expressed as a percent of PEC, range from 180% for Unit 1 

to 200% for Unit 3. In other words, the Black & Veatch indirect costs are well over a 

factor of two higher than recommended in the Cost Manual. These excessive costs are 

unsupported. Some of these costs are discussed below. 

1. Engineering

 The Black & Veatch analyses calculated engineering as 7% of total direct costs, 

owner's cost as 5% of total direct cost, and construction management as 10% of direct 

costs. These costs are overestimated. Engineering costs, for example, are overestimated 

as they failed to take into account the reduction in engineering costs for duplication in the 

design of Units 1 and 2 and Units 3 and 4.78 

 This method deviates from the Cost Manual, which combines these costs in a 

single factor reported as engineering and home office fees calculated as 10% of total 

direct cost79. This change is made in my cost estimates (Exhibit 1, Fox Row 52-54). 

2. Owners Cost

The Black & Veatch cost analyses include owner's costs as a separate indirect 

capital cost, estimated as 5% of total direct cost. These are reportedly costs incurred by 

 

76 Email from Norem to Kordzi, October 21, 2010, Re: PNM Responses to Follow-Up Questions from 

October 14, 2010 Conference Call Regarding BART Cost Estimates, Table 1: Presentation of SJRPP 

Estimate to the BART format. 

77 Cost Manual, pdf 216 (carbon absorber 0.31 PEC), 258 (Condenser 0.31PEC), 314 (Flare 0.35PEC), 369 

(Thermal/Catalytic Incinerator 0.31 PEC), 532 (Gas Absorber 0.35PEC), 608 (Fabric Filter 0.45 PEC), 670 

(Venturi Scrubber 0.35PEC), 729 (ESP 0.57PEC). 

78 See, for example, Michael Costanzo and Scott Williams, Boiler Structural Reinforcement Project at 

Belews Creek, Power-Gen International, December 9-11, 2003, p. 3 ("The engineering costs for the second 

unit were much less due to significant duplication in both the original boiler design and the new 

reinforcement materials."). Available here: http://www.babcock.com/library/pdf/BR-1749.pdf 

79 Cost Manual, pdf 483, Table 2.5.. 

19
the owner in managing and implementing a capital project. While owners do incur some 

costs, owners generally do not manage and implement capital projects, but rather retain 

engineering firms, called the owner's engineer, to perform these functions or more 

commonly, hire an EPC contractor to perform the project for a fixed cost. Owner's cost 

is part of the factored estimate for engineering and home office fees, calculated as 10% of 

total direct cost, procurement, and construction management. Owner's costs are not 

separately included in BART cost effectiveness analyses and have been more than double 

counted here. In its May 10, 2010 formal comments to the North Dakota Department of 

Health, for example, EPA rejected the inclusion of "owner's costs" in cost analyses for 

the Milton R. Young. 80 EPA also rejected owner’s costs in its BART evaluation of the 

Four Corners Power Plant.81 Thus, I set owner's cost equal to zero (Exhibit 1, Fox Row 

53). 

3. Construction Indirects

 Construction indirects were estimated as $22.5 million for Unit 1 to $31.8 million 

for Unit 3 in the revised Black & Veatch cost analysis. These figures were further 

escalated to 2010 dollars per the Black & Veatch 10/22/10 cost analysis. Construction 

indirects include construction equipment, temporary facilities, field office supplies, 

temporary utilities, site services, safety, and contractor management.82 Black & Veatch 

calculated these costs as 100% of the labor costs associated with direct construction.83 

There are three issues with this estimate. 

 First, it is inconsistent with the Cost Manual. These costs (general facilities) are 

estimated as 5% of total direct capital cost.84 The Cost Manual method yields a much 

lower estimate than Black & Veatch's. 

 Second, Black & Veatch double counted escalation in its October 2010 estimate. 

They first escalated direct installation costs by 6.2%. They next calculated construction 

indirects as 100% of this escalated labor according to the method laid out in two emails to 

EPA.85 They finally escalated the already escalated construction indirects by an 

additional 6.2%. 

 Third, Black & Veatch's calculations do not consider the weakening of labor 

markets that has occurred since they set up their spreadsheets in 2007. According to 

Black & Veatch, in the pre-2004 period, its estimating department found that construction 

indirects were typically 50% to 60% of installation labor costs. In the post-2005 period, 

they reported construction indirects rose to a range of 90% to 120% of installation labor 

costs due to tightening in labor markets.86 However, in the 2010 revised cost estimate, 

Black & Veatch did not adjust the construction indirects to reflect the loosening up of the 

 

80 Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry O'Clair, 

Director, Division of Air Quality, North Dakota Department of Health, Re: EPA's Comments on the North 

Dakota Department of Health's April 2010 Draft BACT Determination for NOx for the Milton R. Young 

Station, May 10, 2010. 

81 See Four Corners Technical Support Document, Excel spreadsheet entitled "Four Corners SCR Cost 

Analysis 8-26-10," Row 52, in the Four Corners docket #EPA-R09-OAR-2010-0683. 

20
labor market.87 The tightening of the labor markets has now reversed, skilled labor is 

under utilized, and per deim is not being paid at all or only paid for a portion of the labor 

force. 

 To address these issues, I revised construction indirects to 60% of the July 11, 

2007 estimate (Exhibit 1, Row 55), which is the upper end of the pre-2004 range. The 

Cost Manual approach would yield a lower estimate. 

4. Contingencies

 The contingencies included in the Black & Veatch cost estimates are double 

counted and excessive. There are three separate contingencies imbedded in the analysis. 

First, the cost of structural steel (Row 22) and the SCR bypass (Row 23) were increased 

by a factor of 1.2 at Units 1 and 4 and by a factor of 1.5 at Units 2 and 3 to address the 

"significantly more challenging site at San Juan compared to SJRPP."88 Second, a 

separate contingency of $2,000,000 was included for each unit for "site unknowns, such 

as underground utilities" (Row 47) and $500,000 for each unit for "general site building 

requirements" (Row 48). Third, a contingency of 20% of total direct costs (thus building 

contingencies on top of contingencies) was included for each unit under indirect costs 

(Row 58). This latter contingency was based on the CUECost model,89 which has not 

been approved for BART cost analyses. 

 The sum of these contingencies amounts to approximately $18 million for Unit 1, 

$22 million for Unit 2, $27 million for Unit 3, and $23 million for Unit 4, or about two 

thirds of the purchased equipment cost. This is excessive. 

 The Cost Manual stipulates a 5% process contingency for indirect installation 

costs, figured as 5% of total direct costs, and a 15% project contingency, figured as 15% 

of total direct and total indirect installation costs.90 As the Black & Veatch estimates are 

unsupported and inconsistent with other SCR BART and BACT cost effectiveness 

 82 Cost Manual Commentary, p. 12, Sec. 2.16, and Email from Norem to Kordzi, October 21, 2010, PNM 

Responses to Follow-Up Questions from October 14, 2010 Conference Call Regarding BART Cost 

Estimates, Response to Question 5. 

83 Cost Manual Commentary, p. 30; 10/18/2010 email from Norem to Kordzi, Re: Questions on the Cost of 

Materials and Labor; and email from Norem to Kordzi, November 5, 2010. 

84 Cost Manual, pdf 486, Table 2.5. 

85 Cost Manual Commentary, p. 30; 10/18/2010 email from Norem to Kordzi, Re: Questions on the Cost of 

Materials and Labor; and email from Norem to Kordzi, November 5, 2010. 

86 Cost Manual Commentary, p. 30. See also PNM Response to BART Analysis Questions from NMED, 

September 14, 2007, p. 3. 

87 B&V 10/22/10 Cost Analysis, Tables 7 - 10. 

88 10/8/10 Email from Norem to Kordzi, Response to Question 11. 

89 OAQPS Commentary, p. 11. 

90 Cost Manual, pdf 486, Table 2-5. 

21
analyses, I revised the Black & Veatch cost analysis to use the Cost Manual assumptions, 

as required by the BART Guidelines (Exhibit 1, Fox Rows 52, 58). 

5. Interest During Construction

 The Black & Veatch cost estimates include a charge ranging from $16.8 to $22.8 

million for interest during construction. This charge, generally called allowance for 

funds during construction or AFUDC, is disallowed in the Cost Manual for SCRs.91 

Thus, I set it equal to zero in my analyses (Exhibit 1, Row 61). 

 AFUDC is an accounting method. Assets under construction do not provide 

service to current customers and thus associated interest and allowed return on equity are 

not charged to current customers. Instead, AFUDC capitalizes these costs and adds them 

to the rate base so that they can be recovered from future customers when the assets are 

used. Thus, these charges represent future cash income to the utility. In other words, 

AFUDC is the accumulated cost of carrying capital and holding it waiting to spend, so 

money can be made in the future, by selling electricity. Future income should not be 

charged against the cost of a SCR in a BART cost effectiveness analysis. These costs are 

not part of the constant dollar approach found in the EPA Control Cost Manual and 

should not be included in BART cost-effectiveness analyses. 

6. Lost Generation

 The Black & Veatch cost analyses assume a 12 week outage would be required to 

complete the balanced draft conversion The SCR would be installed during the routine 7 

week outage. The remaining 5 weeks is required for the stiffening. This charge is not 

allowed under the Cost Manual. Further, it is unwarranted as the required stiffening work 

can be completed over multiple routine outages. With good planning, no lost generation 

would be incurred. I have set this charge equal to zero (Exhibit 1, Fox Row 62). 

E. Fixed Annual Costs 

 Fixed annual costs include operating labor, maintenance labor and materials, 

emission testing, catalyst activity testing, and fly ash sampling and analysis. Some of 

these costs are overestimated, as explained below. 

1. Operating Labor

 Operating labor was estimated at $125,000/yr for each unit, based on one full time 

equivalent (FTE). However, the Cost Manual explains that the SCR reactor is a 

stationary device with no moving parts and uses only a few pieces of rotating equipment 

(e.g., pumps, motors). Thus, existing plant staff can operate the SCR from the existing 

control room. The Cost Manual explains: "In general, operation of an SCR system does 

 

91 Cost Manual, pdf 486, Table 2.5, E (Allowance for Funds During Construction) = 0. 

22
not require any additional operating or supervisory labor."92 Thus, operating labor was 

set equal to zero in the cost spreadsheets (Exhibit 1, Fox Row 72). 

2. Maintenance Labor & Materials

 Maintenance labor and materials was estimated by Black & Veatch as 3% of the 

total direct costs. However, the Cost Manual reports that maintenance labor and material 

should be estimated as 1.5% of total capital investment93. This change was made to the 

spreadsheets (Exhibit 1, Fox Row 73). 

F. Variable Annual Costs 

 Variable annual costs include reagent (anhydrous ammonia), auxiliary and ID fan 

power, and catalyst replacement. Some of these costs are overestimated, as explained 

below. In discussing the overestimates for ammonia and replacement catalyst, I consider 

two cases. The first, the 0.07 lb/MMBtu case, was evaluated in the Black & Veatch cost 

analysis and assumes the SCR is designed to meet an outlet NOx emission limit of 0.07 

lb/MMBtu. The second, the 0.05 lb/MMBtu case, was requested by EPA and assumes 

the SCR is designed to meet an outlet NOx emission limit of 0.05 lb/MMBtu. This lower 

level can be achieved with the Black & Veatch SCR design by increasing the amount of 

ammonia that is injected. The catalyst was sized to meet 0.05 lb/MMBtu, so no change 

in catalyst volume is required. 

1. Reagent

 The SCR will use anhydrous ammonia, which reacts with NOx to form nitrogen 

gas (N2) and water. The costs were estimated assuming a unit-specific ammonia flow 

rate in lb/hr based on an SCR outlet NOx of 0.06 lb/MMBtu and an ammonia cost of 

$700/ton. 

 First, the ammonia cost is much higher than market prices. As the cost estimate 

has been adjusted to 2010 dollars, the current price of anhydrous ammonia should be 

used. Black & Veatch used an anhydrous ammonia cost of $450/ton in a September 2010 

BART analysis for Boardman.94 Similarly, Sargent & Lundy used an anhydrous 

ammonia cost of $475/ton in a September 2010 BART analysis for the Navajo 

Generating Station.95 Thus, I revised the cost analysis to use $475/ton for ammonia 

(Exhibit 1, Fox Row 80). 

 Second, the ammonia flow rate was estimated assuming an outlet NOx of 0.06 

lb/MMBtu. The emission reductions and proposed BART limit, however, are based on 

0.07 lb/MMBtu. Thus, 0.07 lb/MMBtu should have been used to calculate the ammonia 

demand. I revised the cost analysis to estimate ammonia demand based on reducing NOx 

from 0.30 lb/MMBtu to 0.07 lb/MMBtu by multiplying the ammonia flow rate by the 

 

92 Cost Manual, pdf 487. 

93 Ibid. 

23
ratio 0.23 (0.30-0.06) to 0.24 (0.30-0.07) (Exhibit 1, Fox Row 80, 0.07 cases). For the 

0.05 lb/MMBtu cases, I increased the ammonia flow rate by the ratio of 0.25 (0.30-0.05) 

to 0.24 (0.30 - 0.06) (Exhibit 1, Fox Row 80, 0.05 cases). 

2. Auxiliary Power Cost

 Auxiliary power is the sum of the power required to overcome the increase in 

backpressure from adding the SCR, fan power, and power to operate the ammonia 

injection system. This cost is estimated by multiplying the power demand in kilowatts by 

the cost of electricity in dollars per kilowatt hour. Black & Veatch calculated this cost to 

range from $1.5 million per year for Units 1 and 2 to $2.2 million per year for Units 3 

and 5. 

 First, Black & Veatch assumed a total auxiliary power demand of 16,297 kW for 

the four units, which amounts to 0.9% of the total gross generating capacity of the station. 

An SCR typically uses about 0.3% of a plant's electric output, which would be about 

5,400 kW or three time less than assumed in the cost analysis.96 I revised the auxiliary 

power demand to 0.3% of the gross unit capacity (Exhibit 1, Fox Row 81). 

 Second, the unit cost of electricity used by Black & Veatch, $0.06095/kWh, is 

much higher than the default cost used in cost effectiveness analyses, $0.05/kWh. 

Auxiliary power is the power required to run the plant, or power not sold. Cost 

effectiveness analyses are based on the cost to the owner to generate electricity, or the 

busbar cost, not market retail rates. 

 The Black & Veatch estimate is based on the average forecasted cost of 

replacement power for 2007 to 2012.97 Other recent BART analyses for similar facilities 

have used auxiliary power costs that range from $0.03/kWh to $0.05/kWh.98 Black & 

Veatch used a power cost of $0.04604/kWh in a September 2010 BART analysis for 

 94 Black & Veatch, Portland General Electric Boardman Plant, Best Available Retrofit Technology 

(BART)/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative, August 27, 2010, Table 2-

2. 

95 Sargent & Lundy, Salt River Project Navajo Generating Station - Units 1, 2, 3, SCR and Baghouse 

Capital Cost Estimate Report, Revision D, August 17, 2010, pdf 58, Table 9-2. 

96 Cost Manual, pdf 470. 

97 Email from Norem to Kordzi, October 21, 2010, Re: PNM Responses to Follow-Up Questions from 

October 14, 2010 Conference Call Regarding BART Cost Estimate, October 21, 2010 (10/21/10 

Responses), Response to Question 9, pp. 3-4. 

98 Sargent & Lundy, Sooner Units 1 & 2, Muskogee Units 4 & 5 Dry FGD BART Analysis Follow-Up 

Report, Prepared for Oklahoma Gas & Electric, December 28, 2009 , Attach. C, pdf 109; (Gerald 

Gentleman - $45.65/MWh; White Bluff - $47/MWh; Boardman/Northeastern/Naughton - $50/MWh; 

Nebraska City - $30/MWh). 

24
Boardman.99 Thus, I adjusted the auxiliary power costs to use the upper end of the range, 

$0.050/kWh (Exhibit 1, Fox Row 81). 

3. Catalyst Replacement

 Catalyst replacement costs are overestimated for four reasons. 

 First, the catalyst volume was scaled from another Black & Veatch project, 

Harding Street Unit 7. The scaling took into account the difference in flow rates but not 

the differences in NOx reduction.100 For the 0.07 lb/MMBtu cases, San Juan catalyst 

volume should be based on reducing NOx from 0.3 lb/MMBtu to 0.07 lb/MMBtu or by 

0.23 lb/MMBtu. For the 0.05 lb/MMBtu cases, catalyst volume should be based on 

reducing NOx from 0.3 lb/MMBtu to 0.05 lb/MMBtu or by 0.25 lb/MMBtu. The 

Harding catalyst volume was based on reducing NOx from 0.34 lb/MMBtu to 0.044 

lb/MMBtu or by 0.3 lb/MMBtu.101 When the difference in NOx reduction is factored in, 

catalyst volume, and hence replacement cost, drop by about 15% for the 0.07 lb/MMBtu 

cases and by about 10% for the 0.05 lb/MMBtu cases. 102 

 Second, catalyst replacement cost did not consider catalyst regeneration, which 

has become an attractive alternative to purchasing new catalyst since the Control Cost 

Manual was last updated. The cost of purchasing new catalyst was assumed to be 

$6,500/m3, while the cost to regenerate is about 60% of this price.103 

 Third, setting aside regeneration, the catalyst cost used by Black & Veatch, 

$6,500/m3, is much higher than the cost recently quoted by Hitachi for a nearly identical 

coal, $5,500/m3

 to $6,000/m3.

104 

 

99 Black & Veatch, Portland General Electric Boardman Plant, Best Available Retrofit Technology 

(BART)/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative, August 27, 2010, Table 2-

2. 

100 Email from Norem to Kordzi, October 13, 2010, Re: SJGS BART Analysis - Response on Catalyst 

Sizing Methodology. 

101 The design basis of the Harding SCR was 87.18% NOx reduction to an outlet of 37.8 ppmvd. The 37.8 

ppmvd converts to: (37.8)(9780)(46)/385.5x106

 = 0.044 lb/MMBtu. The inlet NOx: (0.044/(1-8717) = 0.34 

lb/MMBtu. Thus, the Harding SCR was designed to remove 0.3 lb/MMBtu of NOx. 

102 Based on the 10/13/10 Norem email for Unit 3, Black & Veatch estimated catalyst volume for Unit 3 as 

496 m3

, considering only the relative flow rates at Harding and San Juan. Factoring in the NOx reduction 

yields for the 0.07 lb/MMBtu cases: 427 m3

[(3,082.239/2,400.052)(0.23/0.30)]0.6 = 423 m3 . Thus, the 

catalyst volume decreases by (496-423)/496 or by 15%. For the 0.05 lb/MMBtu cases: 427 

m3

[(3,082.239/2,400.052)(0.25/0.30)]0.6 = 445 m3.

 Thus, the catalyst volume decreases by (496-445)/496 or 

by 10%. 

103 Mike Cooper, New Life for Catalyst, Power Engineering, March 2006. available here: 

http://www.gotcatalyst.biz/news/PM20060301.pdf. 

104 Email from Anthony C. Favale, Director - SCR Products, Hitachi Power Systems America, Ltd., to 

Anita Lee, U.S. EPA, Region 9, Re: CX Catalyst Question, April 1, 2010. 

25
 Fourth, the Black & Veatch calculations did not consider the time value of 

money. The Cost Manual explains that the future worth factor should be used to amortize 

the catalyst cost over the years preceding the actual catalyst purchase. As money is 

allocated in advance of purchase, the sum of the annual catalyst replacement cost is less 

than the purchase price of the catalyst. Thus, the purchase price should have been 

multiplied by a future worth factor. Assuming an interest rate of 7%, a catalyst life of 

12,000 hours, and a capacity factor of 85%, the future worth factor is 0.48.105 If a more 

realistic estimate of 24,000 hours for the catalyst life is used, the future worth factor 

drops to 0.31. In other words, the cost of catalyst replacement should be about half of 

what Black & Veatch assumed. 

 Thus, for the 0.07 lb/MMBtu cases, I revised catalyst replacement cost to reduce 

the annual volume by 15%, the unit catalyst cost to $6,000/m3, and to include a future 

worth factor of 0.48 (Exhibit 1, Fox Row 82). For the 0.05 lb/MMBtu cases, I did not 

reduce catalyst volume, reduced unit catalyst cost to $6,000/m3, and used a future worth 

factor of 0.48 (Exhibit 1, Fox Row 82). Additional work is required to assess 

regeneration, which would further lower costs. 

G. Capital Recovery 

 A capital recovery factor or CRF is used to convert a present value into a stream 

of equal annual payments over a given time at a given interest rate. Under the Cost 

Manual methodology, total capital costs are annualized by calculating an annual payment 

sufficient to finance the investment over its entire life. This payment is calculated by 

multiplying the total capital investment by a capital recovery factor calculated from a 

formula based on interest rate and equipment lifetime. The CRF is given by: 

 CRF - [ i(1+i)n

]/[(1+i)n -1 ] 

where i is the interest rate and n is the life of the pollution control equipment. In essence, 

annualization establishes an annual payment sufficient to finance the capital investment 

for its entire life. 106 The longer the equipment life and the lower the interest rate, the 

lower the annualized capital costs and the lower the cost effectiveness in $/ton. 

 Black & Veatch calculated capital recovery costs assuming an interest rate of 

7.41% and an SCR lifetime of 20 years. This is inconsistent with the Cost Manual, which 

requires that the CRF be based on an interest rate of 7% and the actual lifetime of the 

control equipment.107 

 

105 Cost Manual, pdf 489-490, Eqn. 2.52: FWF = 0.07[1/(1.072

-1)] = 0.483. Y = 12,000 hr/(8760)(0.85) = 

1.61, rounded to 2. 

106 Cost Manual, p. 2-21, pdf 35. 

107 While 20 years is used as the equipment life for SCR in the Cost Manual, it should be noted that this is 

merely an assumption for purposes of presenting an example of cost estimation for SCR installation and 

operation in the Cost Manual. Cost Manual, pdf 492. 

26
1. SCR Lifetime

 The lifetime used to calculate the capital recovery factor is the actual (or 

anticipated) service life of the equipment. The lifetime is important because the shorter 

the lifetime, the higher the capital recovery factor and the higher the annual capital cost 

used to determine cost effectiveness. The lifetime of an SCR, which is a metal frame 

packed with catalyst modules, is equal to the lifetime of the boiler, which might easily be 

over 60 years. There are many SCRs installed in Europe in the 1980s that are still in 

operation today. Many utilities routinely specify 30+ year lifetimes in requests for 

proposal and to evaluate proposals. A study of the economic risks from SCR operation at 

the Detroit Edison Monroe power plant, for example, used 30 years as the anticipated 

lifetime.108 An analysis prepared by Black & Veatch for another facility assumed a 40 

year SCR lifetime.109 A 30-year service life is consistent with actual experience with 

existing SCRs and with the nature of the equipment. I used 30 years compared to 20 

years used by Black & Veatch (Exhibit 1, Fox Row 88). Increasing the lifetime from 20 

years to 30 years while holding all else constant would decrease annual capital costs by 

about 17% (0.0944/0.0806), a significant amount when dealing with capital costs of tens 

of millions of dollars. 

When the lifetime of a control effects the BART determination, as here, a 

federally-enforceable restriction is required to prevent further operation after a date 

certain.110 Such a date has not been proposed. 

2. Interest Rate

 Black & Veatch's cost estimate assumed an interest rate of 7.41%. It has long 

been standard practice to use an interest rate of 7% in regulatory cost effectiveness 

analyses, as this is the social cost of borrowing specified for governmental analyses.111

The interest rate used to calculate the capital recovery factor for cost analyses is the 

"social" interest rate established by the Office of Management and Budget (OMB) for 

comparison of public policy issues.112 The latest real interest rate for cost effectiveness 

analyses published by OMB is 2.8%. EPA calculated the CRF using both 3% and 7% 

 

108 S.D. Unwin and others, Selective Catalytic Reduction (SCR) System Design and Operations: 

Quantitative Risk Analysis of Options, Presented at CCPS 17th Annual International Conference: Risk, 

Reliability, and Security, p. 3. Available here: http://www.unwin-co.com/files%5CSCR-RiskPaper,CCPS-RRS2002.pdf. 

109 Email from O'Brien to Van Helvoirt, September 28, 2004, Re: Cost Impact, WPS-011904 at WPS011905. 

110 70 FR 39169 (July 6, 2005). Where the date that a facility permanently stops operation affects the 

BART determination, "this date should be assured by a federally- or State-enforceable restriction 

preventing further operation." 

111 Cost Manual, pdf 27; and Circular A-4, U.S. Office of Management and Budget, September 2003. 

Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/#d. 

112 Cost Manual, pdf 26; and Circular A-4, U.S. Office of Management and Budget, September 2003. 

Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/#d. 

27
interest rates in determining cost effectiveness for the Regulatory Impact Analysis for the 

Final Clean Air Visibility rule and the Guidelines for BART Determinations under the 

Regional Haze regulations.113 Thus, I calculated the CRF using 7% (Exhibit 1, Fox Row 

88). 

H. Other NOx BACT Limits (0.05 Lb/MMBtu Cases) 

 The EPA requested that I estimate the cost of SCR, assuming an outlet NOx of 

0.05 lb/MMBtu. The SCR costed by Black & Veatch could meet this limit on a 30-day 

rolling average basis by increasing the amount of ammonia injected by about 8.7%.114 

The catalyst volume in Black & Veatch's cost analyses is based on reducing NOx from 

0.39 to 0.044 lb/MMBtu,115 or by more than enough to achieve 0.05 lb/MMBtu with a 

significant margin of safety. Thus, no change in catalyst volume is required. Meeting a 

lower outlet NOx also increases NOx emission reductions by 8.7%. These changes 

improve the cost effectiveness of SCR. Cost effectiveness values for the 0.05 lb/MMBtu 

case are as follows: Unit 1 $1,847/ton; Unit 2 $1,920/ton; Unit 3 $1,610/ton; and Unit 4 

$1,579/ton. These calculations are housed in Exhibit 1, Tabs “Unit 1 @ 0.05,” “Unit 2 @ 

0.05,” “Unit 3 @ 0.05,” and “Unit 4 @ 0.05.” 

I. Cost Summary 

 My revisions discussed above improve the cost effectiveness of SCR at San Juan 

for the 0.07 lb/MMBtu case analyzed by Black & Veatch from a range of $6,252/ton to 

$8,378/ton to a range of from $1,549/ton to $2,016/ton (2010 dollars). My revisions also 

reduced the capital costs, expressed as dollars per kilowatt ($/kW), from a range of 

$446/kW to $599/kW116 to a range of $110/kW to $155/kW (2010 dollars). The 0.05 

lb/MMBtu case further reduced cost effectiveness to a range of $1,447/ton to $1,877/ton. 

 Five industry studies conducted between 2002 and 2007 have reported the 

installed unit capital cost of SCRs, or the costs actually incurred by owners, to range from 

$79/kW to $316/kW in 2010 dollars. These actual costs are lower than estimated by 

Black & Veatch for San Juan ($446/kW to $599/kW). 

 

113 See Four Corners Technical Support Document, Excel spreadsheet entitled "Four Corners SCR Cost 

Analysis 8-26-10" in the Four Corners Docket #EPA-R09-OAR-2010-0683. 

114 The increase in ammonia is directly proportional to the increase in NOx reduction (except the slip, 

which is a tiny fraction of the total and which remains constant). Thus, ammonia injection must increase 

by about: (0.3-0.05)/(0.3-0.07) = 1.087. 

115 The Harding Street catalyst volume estimate that Black & Veatch relied on was guaranteed by CERAM 

to reduce NOx to 37.8 ppmvd. Email from Norem to Kordzi, October 13, 2010, Re: SJGS BART Analysis 

- Response on Catalyst Sizing Methodology, CERAM Catalyst Performance. Converting the outlet NOx to 

lb/MMBtu: (37.8 lb)(9780 dscf/MMBtu)(46 lb/lb-mol)/(385.5 ft3

/lb-mol)(106 lb) = 0.044 lb/MMBtu. 

116 The unit capital costs were calculated using Exhibit 1 by replacing line 67, total capital investment, with 

the revised total capital investment from B&V 10/22/10 Cost Analysis, Tables 7-10. This yields: Unit 1 

$539/kW; Unit 2 $599/kW; Unit 3 $482/kW; and Unit 4 $446/kW. 

28
 The first study evaluated the installed costs of more than 20 SCR retrofits from 

1999 to 2001. The installed capital cost ranged from $111 to $223/kW, converted to 

2010 dollars.117 Costs are escalated using the Chemical Engineering Plant Cost Index 

("CEPCI"). 

 The second survey of 40 installations at 24 stations reported a cost range of $79 to 

$254/kW, converted to 2010 dollars.118 The third study, by the Electric Utility Cost 

Group, surveyed 72 units totaling 41 GW, or 39% of installed SCR systems in the U.S. 

This study reported a cost range of $124/kW to $274/kW, converted to 2010 dollars.119 

A fourth study, presented in a course at PowerGen 2005, reported an upper bound range 

of $188/kW to $212/kW, converted to 2010 dollars.120 A fifth summary study reports 

recent applications that were installed in 2006 and 2009. The costs for these units, 

converted to 2010 dollars, ranges from $193/kW to $316/kW. 121 

 Thus, the overall range for these industry studies is $79/kW to $316/kW. The 

upper end of this range is for highly complex retrofits with severe space constraints, such 

as Cinergy's Gibson Units 2 - 4. Gibson, a highly complex, space-constrained retrofit in 

which the SCR was built 230 feet above the power station using the largest crane in the 

world,122 only cost $249/kW in 2010 dollars.123 The San Juan site is not similarly 

constrained. This data indicates that Black & Veatch's estimates of capital cost to retrofit 

 

117 Bill Hoskins, Uniqueness of SCR Retrofits Translates into Broad Cost Variations, Power Engineering, 

May 2003. Available here: 

http://www.powergenworldwide.com/index/display/articledisplay/176832/articles/powerengineering/volume-107/issue-5/features/uniqueness-of-scr-retrofits-translates-into-broad-costvariations.html. The reported range of $80 to $160/kW was converted to 2010 dollars ($111 - $223/kW) 

using the ratio of CEPCI in July 2010 to 2002: 550.7/395.6. 

118 J. Edward Cichanowicz, Why are SCR Costs Still Rising?, Power, April 2004; Jerry Burkett, Readers 

Talk Back, Power, August 2004. The reported range of $56/kW - $185/kW was converted to 2010 dollars 

($79 - $254/kW) using the ratio of CEPCI for July 2010 to 1999 (550.7/390.6) for lower end of the range 

and 2010 to 2003 (550.7/401.7) for upper end of range, based on Figure 3. 

119 M. Marano, Estimating SCR Installation Costs, Power, January/February 2006. The reported range of 

$100 - $221/kW was converted to 2010 dollars ($124 - $274/kW) using the ratio of CEPCI for July 2010 

to 2004: 550.7/444,2. Available here: 

http://findarticles.com/p/articles/mi_qa5392/is_200602/ai_n21409717/print?tag=artBody;col1. 

120 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, Competitive Power 

College, by Babcock Power, Inc. and LG&E Energy, December 2005. The reported range of $160 - 

$180/kW) was converted to 2010 dollars ($188 - $212/kW) using the ratio of CEPCI for July 2010 to 2005 

(550.7/468.2). 

121 J. Edward Cichanowicz, Current Capital Cost and Cost-Effectiveness of Power Plant Emissions Control 

Technologies, June 2007, pp. 28-29, Figure 7-1. The reported range of $175 - $225/kW installed in 2006 

was converted to 2010 dollars ($193 - $248/kW) using the ratio of CEPCI for July 2010 to 2006 

(550.7/499.6). The 2009 value of $300/kW was converted to July 2010 dollars ($316/kW) using the ratio 

of CEPCI for July 2010 to 2009 (550.7/521.9). 

122 Bob Ellis, Standing on the Shoulder of Giants, Modern Power Systems, July 2002. 

123 McIlvaine, NOX Market Update, August 2004. SCR was retrofit on Gibson Units 2-4 in 2002 and 2003 

at $179/kW. Assuming 2002 dollars, this escalates to ($179/kW)(550.7/395.6) = $249/kW. 

http://www.mcilvainecompany.com/sampleupdates/NoxMarketUpdateSample.htm. 

29
SCR at San Juan ($446/kW - $599/kW) are higher than actual installed cost for existing 

retrofit SCRs, including those with extreme retrofit difficulty. 

 Further, the Black & Veatch estimates are much higher than other recent 

estimates, including its own. The unit capital cost for the St. Johns River Power Park 

(SJRPP) SCR that Black & Veatch designed and used to scale costs to the San Juan SCR 

is $187/kW in 2010 dollars.124 This is a factor of two to three less than Black & Veatch 

estimated for San Juan by extrapolating from SJRPP. As explained elsewhere, the SJRPP 

SCR would be more costly than an SCR at San Juan as it burns a very challenging 

coke/coal blend. 

 Other recent estimates confirm that the San Juan SCR capital costs are 

overestimated. Wisconsin Electric estimated the cost to retrofit SCR on Oak Creek Units 

5-8 to be $185/kW125 for a cold-side SCR. This cost was certified in July 2008 for 

construction by the Wisconsin Public Services Commission.126 Wisconsin Power and 

Light estimated the cost to retrofit SCR on the 430-MW Edgewater Unit 5 to be 

$324/kW in January 2008.127 Similarly, American Electric Power (AEP) estimated that 

the average capital cost to install SCRs to remove 85-93% of the NOx from many of its 

units was $162/kW.

128 

 

IV. BART EMISSION RATE 

 The cost effectiveness analysis was based on removing 77% of the NOx, from a 

baseline of 0.30 lb/MMBtu to an outlet of 0.07 lb/MMBtu. SCRs are routinely designed 

and have routinely achieved a NOX control efficiency of 90% and a NOx emission rate as 

low as 0.04 lb/MMBtu,129 based on a 30-day rolling average. 

 

124 Email from Norem to Kordzi, October 21, 2010, PNM Responses to Follow-Up Questions from October 

14, 2010 Conference Call Regarding BART Cost Estimate, Response to Question 7: 

(550.7/499.6)($228,092,914)(/2(675MW)(1000)) = $187.6/kW. 

125 Wisconsin Electric Power Company's Application to Install Wet Flue Gas Desulfurization and Selective 

Catalytic Reduction Facilities and Associated Equipment on Oak Creek Power Plant Units 5, 6, 7 & 8 for 

Control of Sulfur Dioxide and Nitrogen Oxide Emissions, Appendix C, Emission Reduction Study, Volume 

1, Addendum August 20, 2007. Unit cost = ($190,500,000/1,135,000 kW)(550.7/499.6) = $185 kW. 

126 Certificate and Order, Application to Install Wet Flue Gas Desulfurization and Selective Catalytic 

Reduction Facilities and Associated Equipment on Oak Creek Power Plant Units 5, 6, 7 & 8 for Control of 

Sulfur Dioxide and Nitrogen Oxide Emissions, Case 6630-CE-299, July 10, 2008. Available here: 

http://www.we-energies.com/home/OCPP_approvalPSCWOrder.pdf. 

127 Wisconsin Power & Light Co., Certificate of Authority Application, Edgewater Generating Station Unit 

5 NOx Reduction Project, Project Description and Justification, November 2008, PSC Ref#: 105618, p. 11. 

The unit cost was calculated from the total project cost minus escalation divided by gross generating 

capacity or: ($153,944,000 - $14,695,000)/430 MW = $323.8/kW. 

128 AEP, 2008 Fact Book, 43rd Financial Conference, Phoenix, AZ, pdf 103. Available here: 

http://www.aep.com/investors/present/documents/2008EEI-Fact-Book.pdf. 

129 See, e.g., William J. Gretta and others, The SCR Retrofit Design for the Seminole Generating Station, 

PowerGen, 2008, Hitachi SCR at Seminole Electric Delivers 0.04 lb/MMBtu NOx (Preliminary Results), 

FGD and DeNOx Newsletter, December 2009, No. 380, and NOx CEMS data reported to Clean Air 

Markets. 

30
 Vendor experience lists130 indicate that SCRs are routinely designed to achieve 

90% NOX control. Continuous emission monitoring data submitted by utilities to U.S. 

EPA's Clean Air Markets indicate that “90% removal efficiency is currently being 

achieved by a significant portion of the coal-fired SCR fleet.”131 More than 30 units have 

achieved greater than 90% NOX reduction.132 NOX removal of 90% was achieved on 

10,000 MW of coal-fired generation in 2004.133 The McIlvaine Reports, one of the 

sources the NSR Workshop Manual134 states should be considered in a BACT analysis 

(NSR Workshop Manual, p. B.12), reported three of Haldor Topsoe’s SCR installations 

averaged over 95% NOX reduction during the 2005 ozone season.135 

 The U.S. EPA analyzed Clean Air Markets NOX data for twenty two existing 

units that are achieving limits below 0.07 lb/MMBtu on a 30-day rolling average. Eight 

of these units were operating at or above 90% removal efficiency and not one was 

operating at less than 86%.136 Moreover, this data was collected from 2003, before the 

NOX SIP Call and other regulatory programs for NOX were in place. Because 

compliance with the NOx SIP Call was generally not required until May of 2005, 

performance has improved since that point, compared to 2003.137 A recent reanalysis of 

Clean Air Markets data by EPA indicates "many boilers retrofitted with SCR are 

achieving an emission rate of 0.03 - 0.06 lb/MMBtu."138

 SCR system designers have analyzed EPA’s Clean Air Market’s CEMS data to 

determine the NOX levels that are currently being achieved by over 100 SCR-equipped 

coal-fired boilers. This analysis identified 25 units that are achieving NOX emissions less 

 

130 See, e.g., Babcock-Hitachi K.K, NOx Removal Coal Plant Supply List; Argillon Experience List US 

Coal Plants. 

131 James E. Staudt and Clayton Erickson. Selective Catalytic Reduction System Performance and 

Reliability Review, Andover Technology Partners, p. 15. Available here: 

http://www.gaepd.org/air/airpermit/downloads/permits/psd/dockets/longleaf/appealdocs/exhibits/excluded/

Petitioners/P-006-1.pdf. 

132 Ibid., p. 1. 

133 LG&E Energy, Selective Catalytic Reduction: From Planning to Operation, Competitive Power College, 

December 2005, p. 77. 

134 EPA NSR Workshop Manual. Available here: http://www.epa.gov/ttn/nsr/gen/wkshpman.pdf

135 McIlvaine, Utility E-Alert #798. November 3, 2006. 

136 Srivastava et al., Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers, 

Table 4. Available here: 

http://www.netl.doe.gov/technologies/coalpower/ewr/pubs/NOx%20control%20Lani%20AWMA%200905

.pdf. 

137 Manuel J. Oliva and Sikander R. Khan, Performance Analysis of SCR Installations on Coal-Fired 

Boilers, p. 3. 

138 Letter from Callie A. Videtick, Director Air Program, EPA Region 8, to Paul Tourangeau, Director 

Colorado Department of Public Health and the Environment, October 26, 2010, Re: Regional Haze State 

Implementation Plan, p. 3. 

31
than 0.05 lb/MMBtu on an hourly average basis.139 Others have reported similar 

results.140 

 I have previously analyzed 2003 to 2006 Clean Air Markets NOX data, which 

would have been available to Black & Veatch in 2007 when it prepared its BART 

determination. I identified ten SCR retrofit boilers firing a range of bituminous coals and 

coal blends that were achieving a NOX emission limit of 0.05 lb/MMBtu on a 30-day 

rolling average basis or lower. These include Havana Unit 9, Amos Units 1 and 2, 

Chesterfield Unit 6, Cardinal Units 2 and 3, Colbert Unit 5, Ghent Units 3 and 4, and Mill 

Creek Unit 3, among others. The design and performance tests for the latter three units 

have been reported.141 Several others are achieving even lower NOX emission limits 

while firing Powder River Basin coals, including Pleasant Prairie Units 1 and 2 and 

Parish Units 6 and 8. Many more units today are achieving 0.05 lb/MMBtu. For 

example, Havana Unit 9 is achieving a limit of less than 0.04 lb/MMBtu on a 30-day 

rolling basis. Figure 1, which plots the rolling 30-day average, calculated from daily 

averages, shows that the maximum 30 day rolling average at this unit after it switched 

from seasonal to year round operation is 0.0336 lb/MMBtu. 

 

139 Clay Erickson, Robert Lisauskas, and Anthony Licata, What New in SCRs, DOE’s Environmental 

Control Conference, May 16, 2006., p. 28. Available here: 

http://www.netl.doe.gov/publications/proceedings/06/ecc/pdfs/Licata.pdf; LG&E Energy, Selective 

Catalytic Reduction: From Planning to Operation, Competitive Power College, December 2005, p. 75-77. 

140 M.J. Oliva and S.R. Khan, Performance Analysis of SCR Installations on Coal-Fired Boilers, Pittsburgh 

Coal Conference, September 2005. 

141 Eileen Saunders and others, Selective Catalytic Reduction System Performance at LG&E Energy LLC's 

Mill Creek and Ghent Generating Stations, EPRI Workshop on SCR, October 19-20, 2004. Available here: 

http://www.babcockpower.com/pdf/t-197.pdf. 

32
33

. 

 

 Further, permits have been issued to new coal-fired units that include NOX

emission limits of 0.05 lb/MMBtu. These include: 

 

• 0.035 lb/MMBtu 365-day rolling average, Desert Rock, NM (7/31/08)142

• 0.05 lb/MMBtu 30-day rolling average, Desert Rock, NM 7/31/08) 

• 0.05 lb/MMBtu 30-day rolling average, Dallman Unit 4, IL (8/06) 143

• 0.05 lb/MMBtu 12-month rolling, Wygen 3, WY (2/5/07)144

• 0.05 lb/MMBtu 12-month rolling, Dry Fork, WY (10/15/07)145

• 0.05 lb/MMBtu 12-month rolling, Spruce, TX (6/28/05)146

• 0.05 lb/MMBtu annual average, Longleaf, GA (5/14/07)147

 The BART Guidelines note: "... if there is a permit requiring the application of a 

certain technology or emission limit to be achieved for such technology, this usually is 

sufficient justification for you to assume the technical feasibility of that technology or 

emissions limit."148 Spruce and Dallman are operating and meeting their permit limits. 

 

 In addition, Florida Power and Light filed an application in March 2007 for the 

Glades facility with a NOX BACT limit of 0.05 lb/MMBtu based on a 24-hour rolling 

average.149 This facility was rejected by the Florida Public Service Commission based 

on need, but nevertheless, demonstrates that FP&L considered this limit to be achievable

This FP&L limit is more stringent than a 0.05 lb/MMBtu limit based on a 30-day rolling 

average because to meet a limit on a 24-hour basis, the 30-day average must be lower 

than the 24-hour limit.

142 U.S. EPA, Region 9, PSD Permit Issued Pursuant to Requirement at 40 CFR 52.21, PSD Permit Number 

AZP 04-01, Desert Rock Energy Company, July 31, 2008. 

143 Illinois EPA, Construction Permit -- PSD Approval, NSPS Emission Units, Dallman Unit 4, August 10, 

2006, p. 4-13. Limit excludes startups, shutdowns, and malfunctions. 

144 Wyoming Department of Environmental Quality, Black Hills Corporation, Wygen 3, Permit No. CT4517, February 5, 2007. 

145 Wyoming Department of Environmental Quality, Basin Electric Power Corp., Dry Fork Station, Permit 

No. CT-4631, October 15, 2007. 

146 Spruce Special Conditions, Permit Numbers 70492 and PSD-TX-1037, June 28, 2005. 

147 Longleaf Energy Associates, LLC, Air Quality Permit No. 4911-099-0030-P-01-0, May 14, 2007. 

148 70 FR 39165 (July 6, 2005). 

149 FP&L Glades Response to EPA Comments, March 26, 2007, p. 2. 
Exhibit 1. Revised Cost Analyses for SCR at the San Juan Generating Station
2 San Juan Unit 1 

3 Capacity (MWg) 360 4 Capacity (MWn) 327 5 6 COST ANALYSIS B&V 7 8 Cost Item 7/11/2007 Remarks/Cost Basis Escalation Escalation Escalation 9 10/22/2010 to Oct 2011 to Oct 2011 (percent) 1

10 ($) (percent) ($) 11 12 CAPITAL COST 13 Direct Costs 14 Purchased equipment costs 15 Anhydrous Ammonia Injection System $437,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $473,708 5.3 

16 Anhydrous Ammonia Vaporization System $436,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $472,624 5.3 

17 Reactor Box, Breeching and Ductwork $4,005,900 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $4,454,561 0.0 

18 Ductwork Expansion Joints $147,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 8.4 $159,348 5.3 

19 Catalyst $2,557,000 

Catalyst volume determined based on unit size & Nox removal, $6500/m3 of catalyst 0 $2,557,000 0.0 

20 Sonic Horns $188,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $203,792 5.3 

21 Elevator $1,236,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $1,339,824 5.3 

22 Structural Steel $4,881,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $5,427,672 0.0 

23 SCR Bypass $10,000,000 

Taken from another B&V project of similar size 8.4 $10,840,000 5.3 

24 NOx Monitoring System $440,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $476,960 5.3 

25 Electrical System Upgrade $378,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $409,752 11.2 

26 Auxiliary Electrical Equipment Requirements $6,400,000 

Estimated in the B&V 10/22/10 Cost Analysis 0 $6,400,000 0.0 
2

2 San Juan Unit 1 

27 Instrumentation and Control System $279,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $302,436 5.3 

28 Subtotal capital cost (CC) $31,384,900 $33,517,677 $29 Gross Receipt Tax $1,942,000 (CC) X 6.2% $2,074,000 30 Freight $1,569,000 (CC) X 5.0% $1,676,000 31 Total purchased equipment cost (PEC) $34,896,000 $37,268,000 $32 33 Direct installation costs 34 Foundation & supports $10,468,800 (PEC) X 30.0% 6.2 $11,117,866 35 Handling & erection $10,468,800 (PEC) X 30.0% 6.2 $11,117,866 36 Electrical $5,234,400 (PEC) X 15.0% 6.2 $5,558,933 37 Piping $872,400 (PEC) X 2.5% 6.2 $926,489 38 Insulation $3,489,600 (PEC) X 10.0% 6.2 $3,705,955 39 Painting $348,960 (PEC) X 1.0% 6.2 $370,596 40 Demolition $3,489,600 (PEC) X 10.0% 6.2 $3,705,955 41 Relocation $1,744,800 (PEC) X 5.0% 6.2 $1,852,978 42 Total direct installation costs (DIC) $36,117,360 $38,356,636 4.4 43 44 Air preheater modifications $1,071,000 

Based on a budgetary quote received for the project 8.4 $1,160,964 5.3 

45 Balanced draft conversion $14,323,000 

Adjusted from a B&V balanced draft conversion project based on differences in scope 8.4 $15,526,132 5.3 

46 Induced draft fans 5.3 47 Site preparation $2,000,000 

Contingency for site unknowns, such as underground utilities 0 $2,000,000 

48 Buildings & enclosures $500,000 

Contingency for general site building requirements 0 $500,000 

49 Total direct costs (DC) = (PEC) + (DIC) $88,907,000 $94,812,000 $50 51 Indirect Costs 52 Engineering $6,223,490 (DC) X 7.0% $6,636,840 
3

2 San Juan Unit 1 

53 Owner's cost $4,445,350 (DC) X 5.0% $4,740,600 54 Construction management $8,890,700 $9,481,200 55 Construction indirect $22,507,920 B&V labor market review 6.2 $23,903,411 4.4 $56 Start-up and spare parts $2,667,210 (DC) X 3.0% $2,844,360 57 Performance test $200,000 

Based on other projects with similar emissions testing scope $200,000 

58 Contingencies $17,781,400 (DC) X 20.0% $18,962,400 59 Total indirect costs (IC) $62,716,000 $66,769,000 $60 61 Interest During Construction (IDC) $16,853,000 

[(DC)+(IC)] X 7.41% 3 years (project time length X 1/2) $16,853,000 

62 Loss Generation during Outage (GEN) $15,667,000 

5 weeks and 0.06095 $/kWh 12 weeks required for BDC, $15,667,000 

63 

7 weeks major outage available 

64 Project Contingency 65 66 Total Capital Investment 67 (TCI)=(DC)+(IC)+(IDC)+(GEN) $184,143,000 $194,101,000 $68 69 ANNUAL COST 70 Direct Annual Costs 71 Fixed annual costs 72 Operating labor $125,000 

1 FTE and 124,862 $/year Estimated manpower level $125,000 

73 Maintenance labor & materials $2,667,000 (DC) X 3.0% $2,844,000 74 Yearly emissions testing $25,000 

Based on other projects with similar emissions testing scope $25,000 

75 Catalyst activity testing $5,000 Engineering estimate $5,000 76 Fly ash sampling and analysis $20,000 Engineering estimate $20,000 77 Total fixed annual costs $2,842,000 $3,019,000 78 79 Variable annual costs 80 Reagent $911,000 

350 lb/hr and 700 $/ton B&V Calculated $911,000 

81 Auxiliary and ID fan power $1,496,000 

3,287 kW and 0.06095 $/kWh B&V Calculated $1,496,000 
4

2 San Juan Unit 1 

82 Catalyst replacement $426,000 

65 m3 and 6,500 $/m3 2 yr catalyst replacement rate $426,000 

83 Total variable annual costs $2,833,000 $2,833,000 84 85 Total direct annual costs (DAC) $5,675,000 $5,852,000 86 87 Indirect Annual Costs 88 Cost for capital recovery $17,936,000 

(TCI) X 9.74% CRF at 7.41% interest & 20 year life $18,905,000 

89 Total indirect annual costs (IDAC) $17,936,000 $18,905,000 90 91 Total Annual Cost (TAC) = (DAC) + (IDAC) $23,611,000 $24,757,000 92 93 Emission Reductions (ton/yr) 3,174 

B&V BART Analysis, Table ES-2 3,174 

94 95 Cost Effectiveness ($/ton) 7,439 7,800 96 97 Cost ($/kW) 512 539 98 99 

100 101 102 Interest Rate 0.07 103 Lifetime 30 104 CRF 0.0806 
5

2 San Juan Unit 2 3 Capacity (MWg) 350 4 Capacity (MWn) 316 5 6 COST ANALYSIS B&V 7 8 Cost Item 7/11/2007 Remarks/Cost Basis Escalation Escalation Escalation 9 10/22/2010 to Oct 2011 to Oct 2011 (percent) 1

10 ($) (percent) ($) 11 12 CAPITAL COST 13 Direct Costs 14 Purchased equipment costs 15 Anhydrous Ammonia Injection System $429,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $465,036 5.3 

16 Anhydrous Ammonia Vaporization System $429,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $465,036 5.3 

17 Reactor Box, Breeching and Ductwork $3,999,600 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $4,447,555 0.0 

18 Ductwork Expansion Joints $147,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 8.4 $159,348 5.3 

19 Catalyst $2,553,000 

Catalyst volume determined based on unit size & Nox removal, $6500/m3 of catalyst 0 $2,553,000 0.0 

20 Sonic Horns $188,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $203,792 5.3 

21 Elevator $1,236,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $1,339,824 5.3 

22 Structural Steel $5,998,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $6,669,776 0.0 

23 SCR Bypass $10,000,000 

Taken from another B&V project of similar size 8.4 $10,840,000 5.3 

24 NOx Monitoring System $440,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $476,960 5.3 
6

2 San Juan Unit 2 

25 Electrical System Upgrade $372,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $403,248 11.2 

26 Auxiliary Electrical Equipment Requirements $6,400,000 

Estimated in the B&V 10/22/10 Cost Analysis 0 $6,400,000 0.0 

27 Instrumentation and Control System $278,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $301,352 5.3 

28 Subtotal capital cost (CC) $32,469,600 $34,724,927 $29 Gross Receipt Tax $2,009,000 (CC) X 6.2% $2,149,000 30 Freight $1,623,000 (CC) X 5.0% $1,736,000 31 Total purchased equipment cost (PEC) $36,102,000 $38,610,000 $32 33 Direct installation costs 34 Foundation & supports $10,830,600 (PEC) X 30.0% 6.2 $11,502,097 35 Handling & erection $14,440,800 (PEC) X 30.0% 6.2 $15,336,130 36 Electrical $5,415,300 (PEC) X 15.0% 6.2 $5,751,049 37 Piping $902,550 (PEC) X 2.5% 6.2 $958,508 38 Insulation $3,610,200 (PEC) X 10.0% 6.2 $3,834,032 39 Painting $361,020 (PEC) X 1.0% 6.2 $383,403 40 Demolition $3,610,200 (PEC) X 10.0% 6.2 $3,834,032 41 Relocation $1,805,100 (PEC) X 5.0% 6.2 $1,917,016 42 Total direct installation costs (DIC) $40,975,770 $43,516,268 4.4 43 44 Air preheater modifications $1,071,000 

Based on a budgetary quote received for the project 8.4 $1,160,964 5.3 

45 Balanced draft conversion $14,323,000 

Adjusted from a B&V balanced draft conversion project based on differences in scope 8.4 $15,526,132 5.3 

46 Induced draft fans 5.3 47 Site preparation $2,000,000 

Contingency for site unknowns, such as underground utilities 0 $2,000,000 

48 Buildings & enclosures $500,000 

Contingency for general site building requirements 0 $500,000 

49 Total direct costs (DC) = (PEC) + (DIC) $94,972,000 $101,313,000 $50 
7

2 San Juan Unit 2 

51 Indirect Costs 52 Engineering $6,648,040 (DC) X 7.0% $7,091,910 53 Owner's cost $4,748,600 (DC) X 5.0% $5,065,650 54 Construction management $9,497,200 (DC) X 10.0% $10,131,300 55 Construction indirect $26,895,990 B&V labor market review 6.2 $28,563,541 4.4 $56 Start-up and spare parts $2,849,160 (DC) X 3.0% $3,039,390 57 Performance test $200,000 

Based on other projects with similar emissions testing scope $200,000 

58 Contingencies $18,994,400 (DC) X 20.0% $20,262,600 59 Total indirect costs (IC) $69,833,000 $74,354,000 $60 61 Interest During Construction (IDC) $18,318,000 

[(DC)+(IC)] X 7.41% 3 years (project time length X 1/2) $18,318,000 

62 Loss Generation during Outage (GEN) $15,231,000 

5 weeks and 0.06095 $/kWh 12 weeks required for BDC, $15,667,000 

63 

7 weeks major outage available 

64 Project Contingency 65 66 Total Capital Investment 67 (TCI)=(DC)+(IC)+(IDC)+(GEN) $198,354,000 $209,652,000 $68 69 ANNUAL COST 70 Direct Annual Costs 71 Fixed annual costs 72 Operating labor $125,000 

1 FTE and 124,862 $/year Estimated manpower level $125,000 

73 Maintenance labor & materials $2,849,000 (DC) X 3.0% $3,039,000 74 Yearly emissions testing $25,000 

Based on other projects with similar emissions testing scope $25,000 

75 Catalyst activity testing $5,000 Engineering estimate $5,000 76 Fly ash sampling and analysis $20,000 Engineering estimate $20,000 77 Total fixed annual costs $3,024,000 $3,214,000 78 79 Variable annual costs 
8

2 San Juan Unit 2 

80 Reagent $906,000 

348 lb/hr and 700 $/ton B&V Calculated $906,000 

81 Auxiliary and ID fan power $1,492,000 

3,287 kW and 0.06095 $/kWh B&V Calculated $1,492,000 

82 Catalyst replacement $426,000 

65 m3 and 6,500 $/m3 2 yr catalyst replacement rate $426,000 

83 Total variable annual costs $2,824,000 $2,824,000 84 85 Total direct annual costs (DAC) $5,848,000 $6,038,000 86 87 Indirect Annual Costs 88 Cost for capital recovery $19,320,000 

(TCI) X 9.74% CRF at 7.41% interest & 20 year life $20,420,000 

89 Total indirect annual costs (IDAC) $19,320,000 $20,420,000 90 91 Total Annual Cost (TAC) = (DAC) + (IDAC) $25,168,000 $26,458,000 92 93 Emission Reductions (ton/yr) 3,158 

B&V BART Analysis, Table ES-2 3,158 

94 95 Cost Effectiveness ($/ton) 7,970 8,378 96 97 Cost ($/kW) 567 599 98 99 

100 101 102 Interest Rate 0.07 103 Lifetime 30 104 CRF 0.0806 
9

2 San Juan Unit 3 3 Capacity (MWg) 544 4 Capacity (MWn) 497 5 6 COST ANALYSIS B&V 7 8 Cost Item 7/11/2007 Remarks/Cost Basis Escalation Escalation Escalation 9 10/22/2010 to Oct 2011 to Oct 2011 (percent) 1

10 ($) (percent) ($) 11 12 CAPITAL COST 13 Direct Costs 14 Purchased equipment costs 15 Anhydrous Ammonia Injection System $559,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $605,956 5.3 

16 Anhydrous Ammonia Vaporization System $559,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $605,956 5.3 

17 Reactor Box, Breeching and Ductwork $5,051,700 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $5,617,490 0.0 

18 Ductwork Expansion Joints $185,500 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 8.4 $201,082 5.3 

19 Catalyst $3,225,000 

Catalyst volume determined based on unit size & Nox removal, $6500/m3 of catalyst 0 $3,225,000 0.0 

20 Sonic Horns $188,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $203,792 5.3 

21 Elevator $1,236,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $1,339,824 5.3 

22 Structural Steel $7,816,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 8.4 $8,472,544 0.0 

23 SCR Bypass $10,000,000 

Taken from another B&V project of similar size 11.2 $11,120,000 5.3 

24 NOx Monitoring System $440,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $476,960 5.3 
10

2 San Juan Unit 3 

25 Electrical System Upgrade $484,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $524,656 11.2 

26 Auxiliary Electrical Equipment Requirements $8,350,000 

Estimated in the B&V 10/22/10 Cost Analysis 0 $8,350,000 0.0 

27 Instrumentation and Control System $291,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $315,444 5.3 

28 Subtotal capital cost (CC) $38,385,200 $41,058,704 $29 Gross Receipt Tax $2,375,000 (CC) X 6.2% $2,541,000 30 Freight $1,919,000 (CC) X 5.0% $2,053,000 31 Total purchased equipment cost (PEC) $42,679,000 $45,653,000 $32 33 Direct installation costs 34 Foundation & supports $12,803,700 (PEC) X 30.0% 6.2 $13,597,529 35 Handling & erection $17,071,600 (PEC) X 40.0% 6.2 $18,130,039 36 Electrical $6,401,850 (PEC) X 15.0% 6.2 $6,798,765 37 Piping $1,066,975 (PEC) X 2.5% 6.2 $1,133,127 38 Insulation $4,267,900 (PEC) X 10.0% 6.2 $4,532,510 39 Painting $426,790 (PEC) X 1.0% 6.2 $453,251 40 Demolition $4,267,900 (PEC) X 10.0% 6.2 $4,532,510 41 Relocation $2,133,950 (PEC) X 5.0% 6.2 $2,266,255 42 Total direct installation costs (DIC) $48,440,665 $51,443,986 4.4 $43 44 Air preheater modifications $5,090,000 

Based on a budgetary quote received for the project 8.4 $5,517,560 5.3 

45 Balanced draft conversion $18,714,000 

Adjusted from a B&V balanced draft conversion project based on differences in scope 8.4 $20,285,976 5.3 

46 Induced draft fans 5.3 47 Site preparation $2,000,000 

Contingency for site unknowns, such as underground utilities 0 $2,000,000 

48 Buildings & enclosures $500,000 

Contingency for general site building requirements 0 $500,000 

49 Total direct costs (DC) = (PEC) + (DIC) $117,424,000 $125,401,000 $50 
11

2 San Juan Unit 3 

51 Indirect Costs 52 Engineering $8,219,680 (DC) X 7.0% $8,778,070 53 Owner's cost $5,871,200 (DC) X 5.0% $6,270,050 54 Construction management $11,742,400 (DC) X 10.0% $12,540,100 55 Construction indirect $31,795,855 B&V labor market review 6.2 $33,767,198 4.4 $56 Start-up and spare parts $3,522,720 (DC) X 3.0% $3,762,030 57 Performance test $200,000 

Based on other projects with similar emissions testing scope $200,000 

58 Contingencies $23,484,800 (DC) X 20.0% $25,080,200 59 Total indirect costs (IC) $84,837,000 $90,398,000 $60 61 Interest During Construction (IDC) $22,481,000 

[(DC)+(IC)] X 7.41% 3 years (project time length X 1/2) $22,481,000 

62 Loss Generation during Outage (GEN) $23,674,000 

5 weeks and 0.06095 $/kWh 12 weeks required for BDC, $23,674,000 

63 

7 weeks major outage available 

64 Project Contingency 65 66 Total Capital Investment 67 (TCI)=(DC)+(IC)+(IDC)+(GEN) $248,416,000 $261,954,000 $68 69 ANNUAL COST 70 Direct Annual Costs 71 Fixed annual costs 72 Operating labor $125,000 

1 FTE and 124,862 $/year Estimated manpower level $125,000 

73 Maintenance labor & materials $3,523,000 (DC) X 3.0% $3,762,000 74 Yearly emissions testing $25,000 

Based on other projects with similar emissions testing scope $25,000 

75 Catalyst activity testing $5,000 Engineering estimate $5,000 76 Fly ash sampling and analysis $20,000 Engineering estimate $20,000 77 Total fixed annual costs $3,698,000 $3,937,000 78 79 Variable annual costs 
12

2 San Juan Unit 3 

80 Reagent $1,415,000 

543 lb/hr and 700 $/ton B&V Calculated $1,415,000 

81 Auxiliary and ID fan power $2,194,000 

4,881 kW and 0.06095 $/kWh B&V Calculated $2,194,000 

82 Catalyst replacement $538,000 

83 m3 and 6,500 $/m3 2 yr catalyst replacement rate $538,000 

83 Total variable annual costs $4,147,000 $4,147,000 84 85 Total direct annual costs (DAC) $7,845,000 $8,084,000 86 87 Indirect Annual Costs 88 Cost for capital recovery $24,196,000 

(TCI) X 9.74% CRF at 7.41% interest & 20 year life $24,196,000 

89 Total indirect annual costs (IDAC) $24,196,000 $24,196,000 90 91 Total Annual Cost (TAC) = (DAC) + (IDAC) $32,041,000 $32,280,000 92 93 Emission Reductions (ton/yr) 4,931 

B&V BART Analysis, Table ES-2 4,931 

94 95 Cost Effectiveness ($/ton) 6,498 6,546 96 97 Cost ($/kW) 457 482 98 99 

100 101 102 Interest Rate 0.07 103 Lifetime 30 104 CRF 0.0806 
13

2 San Juan Unit 4 3 Capacity (MWg) 544 4 Capacity (MWn) 507 5 6 COST ANALYSIS B&V 7 8 Cost Item 7/11/2007 Remarks/Cost Basis Escalation Escalation Escalation 9 10/22/2010 to Oct 2011 to Oct 2011 (percent) 1

10 ($) (percent) ($) 11 12 CAPITAL COST 13 Direct Costs 14 Purchased equipment costs 15 Anhydrous Ammonia Injection System $559,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $605,956 5.3 

16 Anhydrous Ammonia Vaporization System $559,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $605,956 5.3 

17 Reactor Box, Breeching and Ductwork $5,083,200 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $5,652,518 0.0 

18 Ductwork Expansion Joints $186,500 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 8.4 $202,166 5.3 

19 Catalyst $3,245,000 

Catalyst volume determined based on unit size & Nox removal, $6500/m3 of catalyst 0 $3,245,000 0.0 

20 Sonic Horns $188,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $203,792 5.3 

21 Elevator $1,236,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $1,339,824 5.3 

22 Structural Steel $6,252,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $6,952,224 0.0 

23 SCR Bypass $10,000,000 

Taken from another B&V project of similar size 8.4 $10,840,000 5.3 

24 NOx Monitoring System $440,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $476,960 5.3 
14

2 San Juan Unit 4 

25 Electrical System Upgrade $484,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $524,656 11.2 

26 Auxiliary Electrical Equipment Requirements $8,350,000 

Estimated in the B&V 10/22/10 Cost Analysis 0 $8,350,000 0.0 

27 Instrumentation and Control System $291,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $315,444 5.3 

28 Subtotal capital cost (CC) $36,873,700 $39,314,496 $29 Gross Receipt Tax $2,282,000 (CC) X 6.2% $2,433,000 30 Freight $1,844,000 (CC) X 5.0% $1,966,000 31 Total purchased equipment cost (PEC) $41,000,000 $43,713,496 $32 33 Direct installation costs 34 Foundation & supports $12,300,000 (PEC) X 30.0% 6.2 $13,062,600 35 Handling & erection $12,300,000 (PEC) X 30.0% 6.2 $13,062,600 36 Electrical $6,150,000 (PEC) X 15.0% 6.2 $6,531,300 37 Piping $1,025,000 (PEC) X 2.5% 6.2 $1,088,550 38 Insulation $4,100,000 (PEC) X 10.0% 6.2 $4,354,200 39 Painting $410,000 (PEC) X 1.0% 6.2 $435,420 40 Demolition $4,100,000 (PEC) X 10.0% 6.2 $4,354,200 41 Relocation $2,050,000 (PEC) X 5.0% 6.2 $2,177,100 42 Total direct installation costs (DIC) $42,435,000 $45,065,970 4.4 $43 44 Air preheater modifications $5,090,000 

Based on a budgetary quote received for the project 8.4 $5,517,560 5.3 

45 Balanced draft conversion $18,714,000 

Adjusted from a B&V balanced draft conversion project based on differences in scope 8.4 $20,285,976 5.3 

46 Induced draft fans 5.3 47 Site preparation $2,000,000 

Contingency for site unknowns, such as underground utilities 0 $2,000,000 

48 Buildings & enclosures $500,000 

Contingency for general site building requirements 0 $500,000 

49 Total direct costs (DC) = (PEC) + (DIC) $109,739,000 $117,083,000 $50 
15

2 San Juan Unit 4 

51 Indirect Costs 52 Engineering $7,682,000 (DC) X 7.0% $8,195,810 53 Owner's cost $5,487,000 (DC) X 5.0% $5,854,150 54 Construction management $10,974,000 (DC) X 10.0% $11,708,300 55 Construction indirect $26,445,000 B&V labor market review 6.2 $28,084,590 4.4 $56 Start-up and spare parts $3,292,000 (DC) X 3.0% $3,512,000 57 Performance test $200,000 

Based on other projects with similar emissions testing scope $200,000 

58 Contingencies $21,948,000 (DC) X 20.0% $23,416,600 59 Total indirect costs (IC) $76,028,000 $80,972,000 $60 61 Interest During Construction (IDC) $20,648,000 

[(DC)+(IC)] X 7.41% 3 years (project time length X 1/2) $20,648,000 

62 Loss Generation during Outage (GEN) $23,674,000 

5 weeks and 0.06095 $/kWh 12 weeks required for BDC, $23,674,000 

63 

7 weeks major outage available 

64 Project Contingency 65 66 Total Capital Investment 67 (TCI)=(DC)+(IC)+(IDC)+(GEN) $230,089,000 $242,377,000 $68 69 ANNUAL COST 70 Direct Annual Costs 71 Fixed annual costs 72 Operating labor $125,000 

1 FTE and 124,862 $/year Estimated manpower level $125,000 

73 Maintenance labor & materials $3,292,000 (DC) X 3.0% $3,512,000 74 Yearly emissions testing $25,000 

Based on other projects with similar emissions testing scope $25,000 

75 Catalyst activity testing $5,000 Engineering estimate $5,000 76 Fly ash sampling and analysis $20,000 Engineering estimate $20,000 77 Total fixed annual costs $3,467,000 $3,687,000 78 79 Variable annual costs 
16

2 San Juan Unit 4 

80 Reagent $1,388,000 

533 lb/hr and 700 $/ton B&V Calculated $1,388,000 

81 Auxiliary and ID fan power $2,215,000 

4,881 kW and 0.06095 $/kWh B&V Calculated $2,215,000 

82 Catalyst replacement $541,000 

83 m3 and 6,500 $/m3 2 yr catalyst replacement rate $541,000 

83 Total variable annual costs $4,144,000 $4,144,000 84 85 Total direct annual costs (DAC) $7,611,000 $7,831,000 86 87 Indirect Annual Costs 88 Cost for capital recovery $22,411,000 

(TCI) X 9.74% CRF at 7.41% interest & 20 year life $22,411,000 

89 Total indirect annual costs (IDAC) $22,411,000 $22,411,000 90 91 Total Annual Cost (TAC) = (DAC) + (IDAC) $30,022,000 $30,242,000 92 93 Emission Reductions (ton/yr) 4,837 

B&V BART Analysis, Table ES-2 4,837 

94 95 Cost Effectiveness ($/ton) 6,207 6,252 96 97 Cost ($/kW) 423 446 98 99 

100 101 102 Interest Rate 0.07 103 Lifetime 30 104 CRF 0.0806 
17

2 San Juan Unit 1 @ 0.05 lbs/MMBtu 3 Capacity (MWg) 360 4 Capacity (MWn) 327 5 6 COST ANALYSIS B&V 7 8 Cost Item 7/11/2007 Remarks/Cost Basis Escalation Escalation Escalation 9 10/22/2010 to Oct 2011 to Oct 2011 (percent) 1

10 ($) (percent) ($) 11 12 CAPITAL COST 13 Direct Costs 14 Purchased equipment costs 15 Anhydrous Ammonia Injection System $437,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $473,708 5.3 

16 Anhydrous Ammonia Vaporization System $436,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $472,624 5.3 

17 Reactor Box, Breeching and Ductwork $4,005,900 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $4,454,561 0.0 

18 Ductwork Expansion Joints $147,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 8.4 $159,348 5.3 

19 Catalyst $2,557,000 

Catalyst volume determined based on unit size & Nox removal, $6500/m3 of catalyst 0 $2,557,000 0.0 

20 Sonic Horns $188,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $203,792 5.3 

21 Elevator $1,236,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $1,339,824 5.3 

22 Structural Steel $4,881,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $5,427,672 0.0 

23 SCR Bypass $10,000,000 

Taken from another B&V project of similar size 8.4 $10,840,000 5.3 

24 NOx Monitoring System $440,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $476,960 5.3 
18

2 San Juan Unit 1 @ 0.05 lbs/MMBtu 

25 Electrical System Upgrade $378,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $409,752 11.2 

26 Auxiliary Electrical Equipment Requirements $6,400,000 

Estimated in the B&V 10/22/10 Cost Analysis 0 $6,400,000 0.0 

27 Instrumentation and Control System $279,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $302,436 5.3 

28 Subtotal capital cost (CC) $31,384,900 $33,517,677 $29 Gross Receipt Tax $1,942,000 (CC) X 6.2% $2,074,000 30 Freight $1,569,000 (CC) X 5.0% $1,676,000 31 Total purchased equipment cost (PEC) $34,896,000 $37,268,000 $32 33 Direct installation costs 34 Foundation & supports $10,468,800 (PEC) X 30.0% 6.2 $11,117,866 35 Handling & erection $10,468,800 (PEC) X 30.0% 6.2 $11,117,866 36 Electrical $5,234,400 (PEC) X 15.0% 6.2 $5,558,933 37 Piping $872,400 (PEC) X 2.5% 6.2 $926,489 38 Insulation $3,489,600 (PEC) X 10.0% 6.2 $3,705,955 39 Painting $348,960 (PEC) X 1.0% 6.2 $370,596 40 Demolition $3,489,600 (PEC) X 10.0% 6.2 $3,705,955 41 Relocation $1,744,800 (PEC) X 5.0% 6.2 $1,852,978 42 Total direct installation costs (DIC) $36,117,360 $38,356,636 4.4 43 44 Air preheater modifications $1,071,000 

Based on a budgetary quote received for the project 8.4 $1,160,964 5.3 

45 Balanced draft conversion $14,323,000 

Adjusted from a B&V balanced draft conversion project based on differences in scope 8.4 $15,526,132 5.3 

46 Induced draft fans 5.3 47 Site preparation $2,000,000 

Contingency for site unknowns, such as underground utilities 0 $2,000,000 

48 Buildings & enclosures $500,000 

Contingency for general site building requirements 0 $500,000 

49 Total direct costs (DC) = (PEC) + (DIC) $88,907,000 $94,812,000 $50 
19

2 San Juan Unit 1 @ 0.05 lbs/MMBtu 

51 Indirect Costs 52 Engineering $6,223,490 (DC) X 7.0% $6,636,840 53 Owner's cost $4,445,350 (DC) X 5.0% $4,740,600 54 Construction management $8,890,700 (DC) X 10.0% $9,481,200 55 Construction indirect $22,507,920 B&V labor market review 6.2 $23,903,411 4.4 $56 Start-up and spare parts $2,667,210 (DC) X 3.0% $2,844,360 57 Performance test $200,000 

Based on other projects with similar emissions testing scope $200,000 

58 Contingencies $17,781,400 (DC) X 20.0% $18,962,400 59 Total indirect costs (IC) $62,716,000 $66,769,000 $60 61 Interest During Construction (IDC) $16,853,000 

[(DC)+(IC)] X 7.41% 3 years (project time length X 1/2) $16,853,000 

62 Loss Generation during Outage (GEN) $15,667,000 

5 weeks and 0.06095 $/kWh 12 weeks required for BDC, $15,667,000 

63 

7 weeks major outage available 

64 Project Contingency 65 66 Total Capital Investment 67 (TCI)=(DC)+(IC)+(IDC)+(GEN) $184,143,000 $194,101,000 $68 69 ANNUAL COST 70 Direct Annual Costs 71 Fixed annual costs 72 Operating labor $125,000 

1 FTE and 124,862 $/year Estimated manpower level $125,000 

73 Maintenance labor & materials $2,667,000 (DC) X 3.0% $2,844,000 74 Yearly emissions testing $25,000 

Based on other projects with similar emissions testing scope $25,000 

75 Catalyst activity testing $5,000 Engineering estimate $5,000 76 Fly ash sampling and analysis $20,000 Engineering estimate $20,000 77 Total fixed annual costs $2,842,000 $3,019,000 78 79 Variable annual costs 
20

2 San Juan Unit 1 @ 0.05 lbs/MMBtu 

80 Reagent $911,000 

350 lb/hr and 700 $/ton B&V Calculated $911,000 

81 Auxiliary and ID fan power $1,496,000 

3,287 kW and 0.06095 $/kWh B&V Calculated $1,496,000 

82 Catalyst replacement $426,000 

65 m3 and 6,500 $/m3 2 yr catalyst replacement rate $426,000 

83 Total variable annual costs $2,833,000 $2,833,000 84 85 Total direct annual costs (DAC) $5,675,000 $5,852,000 86 87 Indirect Annual Costs 88 Cost for capital recovery $17,936,000 

(TCI) X 9.74% CRF at 7.41% interest & 20 year life $18,905,000 

89 Total indirect annual costs (IDAC) $17,936,000 $18,905,000 90 91 Total Annual Cost (TAC) = (DAC) + (IDAC) $23,611,000 $24,757,000 92 93 Emission Reductions (ton/yr) 3,174 

B&V BART Analysis, Table ES-2 3,174 

94 95 Cost Effectiveness ($/ton) 7,439 7,800 96 97 Cost ($/kW) 512 539 98 99 

100 101 102 Interest Rate 0.07 103 Lifetime 30 104 CRF 0.0806 
21

2 San Juan Unit 2 @ 0.05 lbs/MMBtu 3 Capacity (MWg) 350 4 Capacity (MWn) 316 5 6 COST ANALYSIS B&V 7 8 Cost Item 7/11/2007 Remarks/Cost Basis Escalation Escalation Escalation 9 10/22/2010 to Oct 2011 to Oct 2011 (percent) 1

10 ($) (percent) ($) 11 12 CAPITAL COST 13 Direct Costs 14 Purchased equipment costs 15 Anhydrous Ammonia Injection System $429,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $465,036 5.3 

16 Anhydrous Ammonia Vaporization System $429,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $465,036 5.3 

17 Reactor Box, Breeching and Ductwork $3,999,600 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $4,447,555 0.0 

18 Ductwork Expansion Joints $147,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 8.4 $159,348 5.3 

19 Catalyst $2,553,000 

Catalyst volume determined based on unit size & Nox removal, $6500/m3 of catalyst 0 $2,553,000 0.0 

20 Sonic Horns $188,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $203,792 5.3 

21 Elevator $1,236,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $1,339,824 5.3 

22 Structural Steel $5,998,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $6,669,776 0.0 

23 SCR Bypass $10,000,000 

Taken from another B&V project of similar size 8.4 $10,840,000 5.3 

24 NOx Monitoring System $440,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $476,960 5.3 
22

2 San Juan Unit 2 @ 0.05 lbs/MMBtu 

25 Electrical System Upgrade $372,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $403,248 11.2 

26 Auxiliary Electrical Equipment Requirements $6,400,000 

Estimated in the B&V 10/22/10 Cost Analysis 0 $6,400,000 0.0 

27 Instrumentation and Control System $278,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $301,352 5.3 

28 Subtotal capital cost (CC) $32,469,600 $34,724,927 $29 Gross Receipt Tax $2,009,000 (CC) X 6.2% $2,149,000 30 Freight $1,623,000 (CC) X 5.0% $1,736,000 31 Total purchased equipment cost (PEC) $36,102,000 $38,610,000 $32 33 Direct installation costs 34 Foundation & supports $10,830,600 (PEC) X 30.0% 6.2 $11,502,097 35 Handling & erection $14,440,800 (PEC) X 30.0% 6.2 $15,336,130 36 Electrical $5,415,300 (PEC) X 15.0% 6.2 $5,751,049 37 Piping $902,550 (PEC) X 2.5% 6.2 $958,508 38 Insulation $3,610,200 (PEC) X 10.0% 6.2 $3,834,032 39 Painting $361,020 (PEC) X 1.0% 6.2 $383,403 40 Demolition $3,610,200 (PEC) X 10.0% 6.2 $3,834,032 41 Relocation $1,805,100 (PEC) X 5.0% 6.2 $1,917,016 42 Total direct installation costs (DIC) $40,975,770 $43,516,268 4.4 43 44 Air preheater modifications $1,071,000 

Based on a budgetary quote received for the project 8.4 $1,160,964 5.3 

45 Balanced draft conversion $14,323,000 

Adjusted from a B&V balanced draft conversion project based on differences in scope 8.4 $15,526,132 5.3 

46 Induced draft fans 5.3 47 Site preparation $2,000,000 

Contingency for site unknowns, such as underground utilities 0 $2,000,000 

48 Buildings & enclosures $500,000 

Contingency for general site building requirements 0 $500,000 

49 Total direct costs (DC) = (PEC) + (DIC) $94,972,000 $101,313,000 $50 
23

2 San Juan Unit 2 @ 0.05 lbs/MMBtu 

51 Indirect Costs 52 Engineering $6,648,040 (DC) X 7.0% $7,091,910 53 Owner's cost $4,748,600 (DC) X 5.0% $5,065,650 54 Construction management $9,497,200 (DC) X 10.0% $10,131,300 55 Construction indirect $26,895,990 B&V labor market review 6.2 $28,563,541 4.4 $56 Start-up and spare parts $2,849,160 (DC) X 3.0% $3,039,390 57 Performance test $200,000 

Based on other projects with similar emissions testing scope $200,000 

58 Contingencies $18,994,400 (DC) X 20.0% $20,262,600 59 Total indirect costs (IC) $69,833,000 $74,354,000 $60 61 Interest During Construction (IDC) $18,318,000 

[(DC)+(IC)] X 7.41% 3 years (project time length X 1/2) $18,318,000 

62 Loss Generation during Outage (GEN) $15,231,000 

5 weeks and 0.06095 $/kWh 12 weeks required for BDC, $15,667,000 

63 

7 weeks major outage available 

64 Project Contingency 65 66 Total Capital Investment 67 (TCI)=(DC)+(IC)+(IDC)+(GEN) $198,354,000 $209,652,000 $68 69 ANNUAL COST 70 Direct Annual Costs 71 Fixed annual costs 72 Operating labor $125,000 

1 FTE and 124,862 $/year Estimated manpower level $125,000 

73 Maintenance labor & materials $2,849,000 (DC) X 3.0% $3,039,000 74 Yearly emissions testing $25,000 

Based on other projects with similar emissions testing scope $25,000 

75 Catalyst activity testing $5,000 Engineering estimate $5,000 76 Fly ash sampling and analysis $20,000 Engineering estimate $20,000 77 Total fixed annual costs $3,024,000 $3,214,000 78 79 Variable annual costs 
24

2 San Juan Unit 2 @ 0.05 lbs/MMBtu 

80 Reagent $906,000 

348 lb/hr and 700 $/ton B&V Calculated $906,000 

81 Auxiliary and ID fan power $1,492,000 

3,287 kW and 0.06095 $/kWh B&V Calculated $1,492,000 

82 Catalyst replacement $426,000 

65 m3 and 6,500 $/m3 2 yr catalyst replacement rate $426,000 

83 Total variable annual costs $2,824,000 $2,824,000 84 85 Total direct annual costs (DAC) $5,848,000 $6,038,000 86 87 Indirect Annual Costs 88 Cost for capital recovery $19,320,000 

(TCI) X 9.74% CRF at 7.41% interest & 20 year life $20,420,000 

89 Total indirect annual costs (IDAC) $19,320,000 $20,420,000 90 91 Total Annual Cost (TAC) = (DAC) + (IDAC) $25,168,000 $26,458,000 92 93 Emission Reductions (ton/yr) 3,158 

B&V BART Analysis, Table ES-2 3,158 

94 95 Cost Effectiveness ($/ton) 7,970 8,378 96 97 Cost ($/kW) 567 599 98 99 

100 101 102 Interest Rate 0.07 103 Lifetime 30 104 CRF 0.0806 
25

2 San Juan Unit 3 @ 0.05 lbs/MMBtu 3 Capacity (MWg) 544 4 Capacity (MWn) 497 5 6 COST ANALYSIS B&V 7 8 Cost Item 7/11/2007 Remarks/Cost Basis Escalation Escalation Escalation 9 10/22/2010 to Oct 2011 to Oct 2011 (percent) 1

10 ($) (percent) ($) 11 12 CAPITAL COST 13 Direct Costs 14 Purchased equipment costs 15 Anhydrous Ammonia Injection System $559,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $605,956 5.3 

16 Anhydrous Ammonia Vaporization System $559,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $605,956 5.3 

17 Reactor Box, Breeching and Ductwork $5,051,700 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $5,617,490 0.0 

18 Ductwork Expansion Joints $185,500 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 8.4 $201,082 5.3 

19 Catalyst $3,225,000 

Catalyst volume determined based on unit size & Nox removal, $6500/m3 of catalyst 0 $3,225,000 0.0 

20 Sonic Horns $188,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $203,792 5.3 

21 Elevator $1,236,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $1,339,824 5.3 

22 Structural Steel $7,816,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 8.4 $8,472,544 0.0 

23 SCR Bypass $10,000,000 

Taken from another B&V project of similar size 11.2 $11,120,000 5.3 

24 NOx Monitoring System $440,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $476,960 5.3 
26

2 San Juan Unit 3 @ 0.05 lbs/MMBtu 

25 Electrical System Upgrade $484,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $524,656 11.2 

26 Auxiliary Electrical Equipment Requirements $8,350,000 

Estimated in the B&V 10/22/10 Cost Analysis 0 $8,350,000 0.0 

27 Instrumentation and Control System $291,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $315,444 5.3 

28 Subtotal capital cost (CC) $38,385,200 $41,058,704 $29 Gross Receipt Tax $2,375,000 (CC) X 6.2% $2,541,000 30 Freight $1,919,000 (CC) X 5.0% $2,053,000 31 Total purchased equipment cost (PEC) $42,679,000 $45,653,000 $32 33 Direct installation costs 34 Foundation & supports $12,803,700 (PEC) X 30.0% 6.2 $13,597,529 35 Handling & erection $17,071,600 (PEC) X 40.0% 6.2 $18,130,039 36 Electrical $6,401,850 (PEC) X 15.0% 6.2 $6,798,765 37 Piping $1,066,975 (PEC) X 2.5% 6.2 $1,133,127 38 Insulation $4,267,900 (PEC) X 10.0% 6.2 $4,532,510 39 Painting $426,790 (PEC) X 1.0% 6.2 $453,251 40 Demolition $4,267,900 (PEC) X 10.0% 6.2 $4,532,510 41 Relocation $2,133,950 (PEC) X 5.0% 6.2 $2,266,255 42 Total direct installation costs (DIC) $48,440,665 $51,443,986 4.4 $43 44 Air preheater modifications $5,090,000 

Based on a budgetary quote received for the project 8.4 $5,517,560 5.3 

45 Balanced draft conversion $18,714,000 

Adjusted from a B&V balanced draft conversion project based on differences in scope 8.4 $20,285,976 5.3 

46 Induced draft fans 5.3 47 Site preparation $2,000,000 

Contingency for site unknowns, such as underground utilities 0 $2,000,000 

48 Buildings & enclosures $500,000 

Contingency for general site building requirements 0 $500,000 

49 Total direct costs (DC) = (PEC) + (DIC) $117,424,000 $125,401,000 $50 
27

2 San Juan Unit 3 @ 0.05 lbs/MMBtu 

51 Indirect Costs 52 Engineering $8,219,680 (DC) X 7.0% $8,778,070 53 Owner's cost $5,871,200 (DC) X 5.0% $6,270,050 54 Construction management $11,742,400 (DC) X 10.0% $12,540,100 55 Construction indirect $31,795,855 B&V labor market review 6.2 $33,767,198 4.4 $56 Start-up and spare parts $3,522,720 (DC) X 3.0% $3,762,030 57 Performance test $200,000 

Based on other projects with similar emissions testing scope $200,000 

58 Contingencies $23,484,800 (DC) X 20.0% $25,080,200 59 Total indirect costs (IC) $84,837,000 $90,398,000 $60 61 Interest During Construction (IDC) $22,481,000 

[(DC)+(IC)] X 7.41% 3 years (project time length X 1/2) $22,481,000 

62 Loss Generation during Outage (GEN) $23,674,000 

5 weeks and 0.06095 $/kWh 12 weeks required for BDC, $23,674,000 

63 

7 weeks major outage available 

64 Project Contingency 65 66 Total Capital Investment 67 (TCI)=(DC)+(IC)+(IDC)+(GEN) $248,416,000 $261,954,000 $68 69 ANNUAL COST 70 Direct Annual Costs 71 Fixed annual costs 72 Operating labor $125,000 

1 FTE and 124,862 $/year Estimated manpower level $125,000 

73 Maintenance labor & materials $3,523,000 (DC) X 3.0% $3,762,000 74 Yearly emissions testing $25,000 

Based on other projects with similar emissions testing scope $25,000 

75 Catalyst activity testing $5,000 Engineering estimate $5,000 76 Fly ash sampling and analysis $20,000 Engineering estimate $20,000 77 Total fixed annual costs $3,698,000 $3,937,000 78 79 Variable annual costs 
28

2 San Juan Unit 3 @ 0.05 lbs/MMBtu 

80 Reagent $1,415,000 

543 lb/hr and 700 $/ton B&V Calculated $1,415,000 

81 Auxiliary and ID fan power $2,194,000 

4,881 kW and 0.06095 $/kWh B&V Calculated $2,194,000 

82 Catalyst replacement $538,000 

83 m3 and 6,500 $/m3 2 yr catalyst replacement rate $538,000 

83 Total variable annual costs $4,147,000 $4,147,000 84 85 Total direct annual costs (DAC) $7,845,000 $8,084,000 86 87 Indirect Annual Costs 88 Cost for capital recovery $24,196,000 

(TCI) X 9.74% CRF at 7.41% interest & 20 year life $24,196,000 

89 Total indirect annual costs (IDAC) $24,196,000 $24,196,000 90 91 Total Annual Cost (TAC) = (DAC) + (IDAC) $32,041,000 $32,280,000 92 93 Emission Reductions (ton/yr) 4,931 

B&V BART Analysis, Table ES-2 4,931 

94 95 Cost Effectiveness ($/ton) 6,498 6,546 96 97 Cost ($/kW) 457 482 98 99 

100 101 102 Interest Rate 0.07 103 Lifetime 30 104 CRF 0.0806 
29

2 San Juan Unit 4 @ 0.05 lbs/MMBtu 3 Capacity (MWg) 544 4 Capacity (MWn) 507 5 6 COST ANALYSIS B&V 7 8 Cost Item 7/11/2007 Remarks/Cost Basis Escalation Escalation Escalation 9 10/22/2010 to Oct 2011 to Oct 2011 (percent) 1

10 ($) (percent) ($) 11 12 CAPITAL COST 13 Direct Costs 14 Purchased equipment costs 15 Anhydrous Ammonia Injection System $559,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $605,956 5.3 

16 Anhydrous Ammonia Vaporization System $559,000 

Scaled from B&V database based on ammonia flow, using 0.6 scale factor 8.4 $605,956 5.3 

17 Reactor Box, Breeching and Ductwork $5,083,200 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $5,652,518 0.0 

18 Ductwork Expansion Joints $186,500 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 8.4 $202,166 5.3 

19 Catalyst $3,245,000 

Catalyst volume determined based on unit size & Nox removal, $6500/m3 of catalyst 0 $3,245,000 0.0 

20 Sonic Horns $188,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $203,792 5.3 

21 Elevator $1,236,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $1,339,824 5.3 

22 Structural Steel $6,252,000 

Scaled from B&V database based on flue gas flow, using 0.6 scale factor 11.2 $6,952,224 0.0 

23 SCR Bypass $10,000,000 

Taken from another B&V project of similar size 8.4 $10,840,000 5.3 

24 NOx Monitoring System $440,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $476,960 5.3 
30

2 San Juan Unit 4 @ 0.05 lbs/MMBtu 

25 Electrical System Upgrade $484,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $524,656 11.2 

26 Auxiliary Electrical Equipment Requirements $8,350,000 

Estimated in the B&V 10/22/10 Cost Analysis 0 $8,350,000 0.0 

27 Instrumentation and Control System $291,000 

Actual price from similarly sized unit, escalated to 2007 dollars 8.4 $315,444 5.3 

28 Subtotal capital cost (CC) $36,873,700 $39,314,496 $29 Gross Receipt Tax $2,282,000 (CC) X 6.2% $2,433,000 30 Freight $1,844,000 (CC) X 5.0% $1,966,000 31 Total purchased equipment cost (PEC) $41,000,000 $43,713,496 $32 33 Direct installation costs 34 Foundation & supports $12,300,000 (PEC) X 30.0% 6.2 $13,062,600 35 Handling & erection $12,300,000 (PEC) X 30.0% 6.2 $13,062,600 36 Electrical $6,150,000 (PEC) X 15.0% 6.2 $6,531,300 37 Piping $1,025,000 (PEC) X 2.5% 6.2 $1,088,550 38 Insulation $4,100,000 (PEC) X 10.0% 6.2 $4,354,200 39 Painting $410,000 (PEC) X 1.0% 6.2 $435,420 40 Demolition $4,100,000 (PEC) X 10.0% 6.2 $4,354,200 41 Relocation $2,050,000 (PEC) X 5.0% 6.2 $2,177,100 42 Total direct installation costs (DIC) $42,435,000 $45,065,970 4.4 $43 44 Air preheater modifications $5,090,000 

Based on a budgetary quote received for the project 8.4 $5,517,560 5.3 

45 Balanced draft conversion $18,714,000 

Adjusted from a B&V balanced draft conversion project based on differences in scope 8.4 $20,285,976 5.3 

46 Induced draft fans 5.3 47 Site preparation $2,000,000 

Contingency for site unknowns, such as underground utilities 0 $2,000,000 

48 Buildings & enclosures $500,000 

Contingency for general site building requirements 0 $500,000 

49 Total direct costs (DC) = (PEC) + (DIC) $109,739,000 $117,083,000 $50 
31

2 San Juan Unit 4 @ 0.05 lbs/MMBtu 

51 Indirect Costs 52 Engineering $7,682,000 (DC) X 7.0% $8,195,810 53 Owner's cost $5,487,000 (DC) X 5.0% $5,854,150 54 Construction management $10,974,000 (DC) X 10.0% $11,708,300 55 Construction indirect $26,445,000 B&V labor market review 6.2 $28,084,590 4.4 $56 Start-up and spare parts $3,292,000 (DC) X 3.0% $3,512,000 57 Performance test $200,000 

Based on other projects with similar emissions testing scope $200,000 

58 Contingencies $21,948,000 (DC) X 20.0% $23,416,600 59 Total indirect costs (IC) $76,028,000 $80,972,000 $60 61 Interest During Construction (IDC) $20,648,000 

[(DC)+(IC)] X 7.41% 3 years (project time length X 1/2) $20,648,000 

62 Loss Generation during Outage (GEN) $23,674,000 

5 weeks and 0.06095 $/kWh 12 weeks required for BDC, $23,674,000 

63 

7 weeks major outage available 

64 Project Contingency 65 66 Total Capital Investment 67 (TCI)=(DC)+(IC)+(IDC)+(GEN) $230,089,000 $242,377,000 $68 69 ANNUAL COST 70 Direct Annual Costs 71 Fixed annual costs 72 Operating labor $125,000 

1 FTE and 124,862 $/year Estimated manpower level $125,000 

73 Maintenance labor & materials $3,292,000 (DC) X 3.0% $3,512,000 74 Yearly emissions testing $25,000 

Based on other projects with similar emissions testing scope $25,000 

75 Catalyst activity testing $5,000 Engineering estimate $5,000 76 Fly ash sampling and analysis $20,000 Engineering estimate $20,000 77 Total fixed annual costs $3,467,000 $3,687,000 78 79 Variable annual costs 
32

2 San Juan Unit 4 @ 0.05 lbs/MMBtu 

80 Reagent $1,388,000 

533 lb/hr and 700 $/ton B&V Calculated $1,388,000 

81 Auxiliary and ID fan power $2,215,000 

4,881 kW and 0.06095 $/kWh B&V Calculated $2,215,000 

82 Catalyst replacement $541,000 

83 m3 and 6,500 $/m3 2 yr catalyst replacement rate $541,000 

83 Total variable annual costs $4,144,000 $4,144,000 84 85 Total direct annual costs (DAC) $7,611,000 $7,831,000 86 87 Indirect Annual Costs 88 Cost for capital recovery $22,411,000 

(TCI) X 9.74% CRF at 7.41% interest & 20 year life $22,411,000 

89 Total indirect annual costs (IDAC) $22,411,000 $22,411,000 90 91 Total Annual Cost (TAC) = (DAC) + (IDAC) $30,022,000 $30,242,000 92 93 Emission Reductions (ton/yr) 4,837 

B&V BART Analysis, Table ES-2 4,837 

94 95 Cost Effectiveness ($/ton) 6,207 6,252 96 97 Cost ($/kW) 423 446 98 99 

100 101 102 Interest Rate 0.07 103 Lifetime 30 104 CRF 0.0806