# 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 E ngineering 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 th e cost of controlling pollution in dollars

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

analysis for the retrofit of selective cata lytic 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 S CR, ranging from $6,252/ton at Unit 4 to

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



# calling the reliability of thes e estimates into question. I reviewed the Black & Veatch

analyses and prepared revised cost effectiven ess analyses, correcting some of the errors

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

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

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

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

Further, the Black & Veatch cost eff ectiveness 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 averag e. However, an emission limit of 0.05

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

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

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

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

lb/MMBtu to 0.05 lb/MMBtu, based on a 30-day ro lling 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 Cont rol 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 Ma nual 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 calcul ation requires that the costs for the control

technology are consistent with th e claimed emission reductions.

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

removed for the source of interest to the ra nge of cost effectiven ess values for other

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

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

source. 5 

# Thus, cost effectiveness is a rela tive determination, based on costs borne by

other similar facilities. To compare cost s 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 st andard procedure developed by EPA used to

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

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

results to costs derived us ing the standard method.

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

used. Otherwise, one runs the risk of co mparing 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 guide lines are contained

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

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

effectiveness. For cost analyses, the Guide lines 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 Buny ak and Sandra V. Silva, Fi sh & 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: "T hese 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 Ai r 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 s hould be based on the OAQPS Cost Control

Manual, where possible." 8



# Black & Veatch did not follow these Guid elines 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 In stitute (EPRI), and whic h is not approved for

BART determinations; extrapolation from seve ral other projects; and its own proprietary

databases.

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

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

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

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

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

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

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

optimize costs; double counting costs; annuali zing costs using an inflated capital

recovery factor; includ ing 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 costi ng method, not to any unique circumstances at

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

documentation be provided for "any unusual circum stances that exist for the source that

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



# As of the time of this writing, PNM ha d provided no documentation regarding unique

circumstances related to the BART determinations.

III. REVISED COST EFFECTIVENESS ANALYSIS

The following sections identify some of th e 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 incorp orated 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/document s/DiscussionofOAQPSCostManualMethodRev080329.

pdf

.

10 

# 70 FR 39168 (July 6, 2005).



# 3

# A. Direct Costs: Purchased Equipment Cost

The direct costs include purchased equi pment 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

Park 11 

# (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. Excer pts from the SJRPP vendor quot es 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 si x-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 it ems to adjust them from budgetary quotes

(used in the 2007 cost analysis) to final contract awards (whi ch 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 scal e the cost of a process or piece of e quipment 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, EP A, 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 ex clude 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 signi ficant challenges du e to the range of

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

practiced at San Juan. The SJRPP fuels incl ude 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) Colo mbian coal. These three fuels coupled with

direct bunkering resulted in de signs 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 thes e 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 inject ion 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 duc twork, reactor housing, and catalys t 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 expe nsive 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 escal ated the original May 2007 costs to

September 2010 using data for certain material s 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 ad justment, 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 lowe r 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 Pl ant Cost Index (CEPCI) 21



# CEPCI

5/07 CEPCI

9/10 Change

CEPCI Change

B&V 22



# 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 Equipment 23 

# 641.6 675.6 5.3 8.4

Buildings 478.7 506.5 5.8 NR

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

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

electrical system upgrade, et c.); and 6.2% to escalate cons truction 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 construc tion labor and construc tion 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 Se rvice, 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 machin ery, 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/superv ision, 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 construc tion cost items overestimates actual costs as

the engineering/supervision componen t has not experien ced any escalation.

3. Anhydrous Ammonia System

The ammonia system consists of an in jection 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 do llars using an esca lation rate of 1.03. 26 

# This

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

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

installation ($18,600), 27 

# which is estimated elsewhere (E xhibit 1, Fox Rows 15 and 16).

4. Reactor Box, Breeching and Ductwork

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

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

Juan units. The final cont ract 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 estimat e 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 maximu m flue gas temperatur es were higher (>750

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

costs by about 10%. 29 

# These factors have been ta ken into account in my revised

estimate (Exhibit 1, Fox R ow 17).

5. Expansion Joints

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

($360,430) instead of one unit, 30 

# using the ratio of volumetri c 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 ra te 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 elsewher e in the Black & Veatch cost analysis.

Finally, the joints are designe d 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 r eactor box, breeching and ductwork, above) to

account for lower operating temperatures, and used the actual flow rates for each unit 34 

# 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 in clude 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 re placing catalyst as an operating

and maintenance (O&M) expense of $426,000 to $541,000 per year 35 

# . 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 1.03 37 

# and further escalated to 2010 dollars per the

Black & Veatch 10/22/10 cost analysis. Howeve r, 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 spreadshee t. 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 subtr acting the capital cost of the sonic horns

from total capital cost before fi guring 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 1.03 38 

# and further escalated to 2010 dollars per the

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

Further, the final contract aw ard 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 sp readsheet and thus are double counted.

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

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

21). 40 

# The double-counted taxes are addressed by subtracting the cap ital cost of the

elevator from total capital cost before fi guring tax (Exhibit 1, Fox Row 29). The doublecounted freight is addressed by subtracting th e 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 estimat ed 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 dolla rs per the Black and Veatch 10/22/10 cost

analysis. The complexity factor is a conti ngency for site congesti on 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 elim inated 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 subtr acting the capital cost of structural steel

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

Even with these adjustments, structur al 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 else where, 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 Proj ect, December 12, 2006 ("Our pr icing 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 dolla rs per the Black & Veatch 10/ 22/10 cost analysis. This

results in a cost of $10 million per unit fo r 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 de signed to remove 92.5% of the NOx, to an

outlet of 0.045 lb/MMBtu, for year round ope ration 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 th at 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 estimate d 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 frei ght 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/M ega08/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 Plan t, 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 assi stance = $7,349, on-site

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



# 10

# counted as they are included elsewhere. Furt her, 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, th e NOx monitoring system cost is based on

final contract award, adjusted to require on ly 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 subtra cting the capital cost of the system from

total capital cost before figuring fr eight (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 to taling 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 margin s 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 benef its the entire fan auxiliary system. The

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

were being designed. Black & Veatch st ates: "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 cumu latively serve the increase in auxiliary

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

control centers that will serve the entire fa n auxiliary loads of bot h the Consent Decree

projects and the SCR. 52 

# Thus, these costs should be pror ated, rather than partitioned to

the last project built.

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

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

Cost Analysis indicate that th e SCRs would increase the dr aft 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 draf t 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). Th us, in my revised cost analysis, I prorated

the cost of the auxiliary power upgrade accordin g 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 hi gh 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 es calation 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 consis t 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. Furthe r, one year of escal ation (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 fi rst quarter of 2007 and dated May 2007.

Thus, my revised cost analysis is ba sed 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 th e capital cost of th e instrumentation and

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

The double-counted installation co st is addressed by subtract ing the capital cost of the

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

Fox Row 42).

B. Other Direct Costs

Direct costs also include certain other co sts 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 4 54



# . In response to an EPA comment, Black & Veat ch 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 cl aimed 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 ba sis for these costs with EPA.

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

burns low sulfur coal. Black & Veatch asse rts 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 c ontaining only 0.77% sulfur. 60 

# These lower sulfur coals

generate very little sulfur trioxide 61 

# 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 modificati ons are not required for the San Juan SC

See discussion of this issue by Sargent & L undy 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 fo r the Ljunstrom Air Preheater, available here:

http://www.airpreheater company.com/Data/DownloadDocum ents/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 Respon se 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, Augu st 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 co ndition 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 ot herwise require upgrading, independe nt of the SCR. Further,

it is unknown whether the costs ar e for replacing all air heater ba skets or just the cold end

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

compelling justification that they are requi red 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 a nd 4 for balanced draft conversions. 63 

# These

figures were further escalate d to 2010 dollars in the Bl ack & 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 incr eased 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 fa ns, a balanced draft conversion with the

proposed stiffening is not part of an SCR project.

Combustion air must be drawn into th e boiler and combustion gases must be

sucked out of the boiler, thr ough the ducts and pollution contro l 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 ai r 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 syst em and out the stack, but also through

any penetrations and seals and into the boile r 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 ot her equipment. This leakage poses various

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

existing pressurized system are being conve rted 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 a nd 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 unde r 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 avoide d 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 ne w induced draft fans between the

pressurized boiler and the stack. 65 

# The resulting systems, pressurized boilers with

downstream induced draft fans, are neither tr ue 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, sti ffening was not required as NFPA 85 67 

# (2004 revision)

did not apply to hybrid systems which were neit her "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 permanen t 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 posit ive 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 pr essure shall be at least as

negative as, but shall not be required to be more negativ e 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 ope rating 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 encl osure shall be designe d 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 th e induced draft fan system with ambient

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

associated equipment.

6.5.1.3.2 Where a furnace pressure c ontrol 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) gene ral structural design requirements and (2)

specific transient design pressure limits.

The general structural design requiremen ts 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 pr essure 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 maxi mum transient design pressures for all

boilers except fluidized-bed boilers for posit ive pressure and all boilers for negative

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

Consent Decree, which were converted to pos itive 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 a nd the stack in the 2004 revision.

The 2007 revision modifies the sections d ealing 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 revi sion is still ambiguous. Section 6.5.1.3,

captioned "balanced draft units," states: "All boile rs 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 cap tioned "balanced draft units," which is not

defined in the code. Thus, it could be interp reted 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 th e boilers were firs t converted to true balanced draft

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

interpretation, stiffeni ng would not be required.

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

plain language of NFPA 85. T hus, none of the stiffening cost s should be attributed after

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

that NFPA 85 does not apply to the hybrid Sa n 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 th e 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 othe r hand, while good engineering design, is

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

the fan modifications required to convert to balanced draft operat ion (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 installa tion costs more than

double the purchased equipment costs.

These are standard cost categories incl uded 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 provi de factors to estimate them for SCR. 73 

# The

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

ranges from 30% for catalytic absorbers and ca rbon absorbers to 85% for gas absor bers.

The factors used for San Juan are un supported in the reco rd, even though New

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

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

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

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

calculation of construction indir ects 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 re ported by others for similar sized units 75



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

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

estimates in other BART analyses and hi gh 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 in stallation costs as 62% of the total purchased

equipment cost (Exhibit 1, Fox Row 42).

D. Indirect Costs

The indirect costs consist of indivi dual 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 cost s 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 Co st Manual range from 31% of PEC for a carbon

absorber or condenser to 57% of PE C 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 Bl ack & Veatch indirect costs are well over a

factor of two higher than recommended in th e 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, a nd 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 reducti on 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 engi neering and home office fees calculated as 10% of total

direct cost 79 

# . 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 Co st 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 capi tal 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 engine er, 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 engineer ing and home office fees , calculated as 10% of

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

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

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

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

the Milton R. Young. 80 

# EPA also rejected owner’s cost s 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 estimate d as $22.5 million for Unit 1 to $31.8 million

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

escalated to 2010 dollars per th e Black & Veatch 10/22/10 costanalysis. 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 Ma nual. 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 cost s by 6.2%. They next calculated construction

indirects as 100% of this escal ated labor according to the met hod 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 co sts. In the post-2005 period,

they reported construction indi rects 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 re flect 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, No rth 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 market s 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 cons truction 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 Bl ack & Veatch cost estimates are double

counted and excessive. There are three separa te 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 f actor 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 include d 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 contingenc y 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 equipm ent cost. This is excessive.

The Cost Manual stipulates a 5% proce ss 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 S CR 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 No rem 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 No rem to Kordzi, November 5, 2010.

86 

# Cost Manual Commentary, p. 30. See also PNM Re sponse 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 an alysis 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 in clude a charge ranging from $16.8 to $22.8

million for interest during construction. Th is 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. Asse ts under construction do not provide

service to current customers and thus associat ed 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 recove red from future customers when the assets are

used. Thus, these charges represent future ca sh 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 effectiven ess 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-effectivene ss analyses.

6. Lost Generation

The Black & Veatch cost analyses assu me 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 requir ed 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 out ages. 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 la bor, maintenance labor and materials,

emission testing, catalyst activ ity testing, and fly ash sampli ng 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 Ma nual 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 Manua l 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 ope rating or supervisory labor." 92 

# Thus, operating labor was

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

2. Maintenance Labor & Materials

Maintenance labor and materials was estim ated 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 investment 93 

# . 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 th ese 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 & V eatch SCR design by increasing the amount of

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

in catalyst volume is required.

1. Reagent

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

gas (N 2 

# ) 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 th an 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 anal ysis to use $475/ton for ammonia

(Exhibit 1, Fox Row 80).

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

lb/MMBtu. The emission reductions and propos ed 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 es timate ammonia demand based on reducing NOx

from 0.30 lb/MMBtu to 0.07 lb/MMBtu by mu ltiplying 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) (Exhi bit 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 dolla rs 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 tota l auxiliary power demand of 16,297 kW for

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

An SCR typically uses about 0.3% of a plan t'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 electricit y 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 analys es 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 Boardm an Plant, Best Available Retrofit Technology

(BART)/Reasonable Progress Analysis Revision 3: Boar dman 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, D ecember 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 a uxiliary 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 pur chasing new catalyst since the Control Cost

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

$6,500/m 3 

# , while the cost to regenerate is about 60% of this price. 103



# Third, setting aside regeneration, the cat alyst cost used by Black & Veatch,

$6,500/m 3 

# , is much higher than the cost recently quoted by Hitachi for a nearly identical

coal, $5,500/m 3 

# to $6,000/m 3



# . 104

99 

# Black & Veatch, Portland General Electric Boardm an Plant, Best Available Retrofit Technology

(BART)/Reasonable Progress Analysis Revision 3: Boar dman 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)/385.5x10 6 

# = 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 m 3 

# , 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 m 3 

# [(3,082.239/2,400.052)(0.23/0.30)] 0.6 

# = 423 m 3 

# . Thus, the

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

m 3 

# [(3,082.239/2,400.052)(0.25/0.30)] 0.6 

# = 445 m 3



# . Thus, the catalyst volume decr eases 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 Pr oducts, Hitachi Power Syst ems 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 c onsider the time value of

money. The Cost Manual explains that the futu re worth factor should be used to amortize

the catalyst cost over the y ears preceding the actual catalyst purchase. As money is

allocated in advance of purchas e, the sum of the annual cataly st 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 hour s for the catalyst life is us ed, 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 revise d catalyst replacement cost to reduce

the annual volume by 15%, the unit catalyst cost to $6,000/m 3 

# , 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/m 3 

# , 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 a nnualized by calculating an annual payment

sufficient to finance the investment over its en tire life. This payment is calculated by

multiplying the total capital investment by a cap ital recovery factor calculated from a

formula based on interest rate and equi pment 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 a nnual payment sufficient to finance the capital investment

for its entire life. 106 

# The longer the equipment life and the lower the inte rest rate, the

lower the annualized cap ital costs and the lower the cost effectiveness in $/ton.

Black & Veatch calculated capital recovery costs assu ming 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/(1.07 2 

# -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 calc ulate the capital recovery factor is the actual (or

anticipated) service life of th e equipment. The lifetime is important because the shorter

the lifetime, the higher the capital recovery f actor and the higher th e 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 sp ecify 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 ex ample, used 30 years as the anticipated

lifetime. 108 

# An analysis prepared by Black & V eatch 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 e quipment. I used 30 years compared to 20

years used by Black & Veatch (Exhibit 1, F ox Row 88). Increasing the lifetime from 20

years to 30 years while holding all else cons tant would decrease annual capital costs by

about 17% (0.0944/0.0806), a significant amount wh en dealing with capital costs of tens

of millions of dollars.

When the lifetime of a control effect s 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 ra te of 7% in regulato ry 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 th at 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 ru le and the Guidelines for BA RT 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 co st 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 am ount 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. Co st 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 dol lars per kilowatt ($/k W), from a range of

$446/kW to $599/kW 116 

# to a range of $110/kW to $ 155/kW (2010 dollars). The 0.05

lb/MMBtu case further reduced cost effec tiveness to a range of $1,447/ton to $1,877/ton.

Five industry studies conducted be tween 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 lowe r 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 proportiona l 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 Ca talyst Performance. Converting the outlet NOx to

lb/MMBtu: (37.8 lb)(9780 dscf/ MMBtu)(46 lb/lb-mol)/(385.5 ft 3 

# /lb-mol)(10 6 

# 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 Chem ical Engineering Plant Cost Index

("CEPCI").

The second survey of 40 in stallations 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, ra nges 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 re trofits with severe space constraints, such

as Cinergy's Gibson Units 2 - 4. Gibson, a highly complex, space-cons trained 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, W hy 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/i s_200602/ai_n21409717/print?tag=artBody;col1.

120 

# PowerGen 2005, Selective Catalytic Reduction: Fr om 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, NO X 

# 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/sample updates/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/kW 125 

# 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 NO X 

# 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 Equipmen t 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 We t Flue Gas Desulfurization and Selective Catalytic

Reduction Facilities and Associated Equipment on Oak Cr eek 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/presen t/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 De livers 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 lists 130 

# indicate that SCRs are r outinely designed to achieve

90% NO X 

# control. Continuous emission monitori ng 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% NO X 

# reduction. 132 

# NO X 

# 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 Manual 134 

# states should be considered in a BACT analysis

(NSR Workshop Manual, p. B.12), reported thre e of Haldor Topsoe’s SCR installations

averaged over 95% NO X 

# reduction during the 2005 ozone season. 135



# The U.S. EPA analyzed Clean Air Markets NO X 

# 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 co llected from 2003, before the

NO X 

# SIP Call and other re gulatory programs for NO X 

# 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 EP A’s Clean Air Market’s CEMS data to

determine the NO X 

# levels that are currently bein g achieved by over 100 SCR-equipped

coal-fired boilers. This analysis id entified 25 units that are achieving NO X 

# emissions less

130 

# See, e.g., Babcock-Hitachi K.K, NOx Removal Co al Plant Supply List; Argillon Experience List US

Coal Plants.

131 

# James E. Staudt and Clayton Erickson. Selec tive 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 Co ntrol Options for Coal-Fired Electric Utility Boilers,

Table 4. Available here:

http://www.netl.doe.gov/technologies/coalpower/e wr/pubs/NOx%20control%20Lani%20AWMA%200905

.pdf.

137 

# Manuel J. Oliva and Sikander R. Khan, Performa nce Analysis of SCR Installations on Coal-Fired

Boilers, p. 3.

138 

# Letter from Callie A. Videtick, Director Air Progra m, 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 NO X 

# data, which

would have been available to Black & V eatch 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 NO X 

# 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 pe rformance tests for th e latter three units

have been reported. 141 

# Several others are achieving even lower NO X 

# emission limits

while firing Powder River Basin coals, in cluding 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 ro lling 30-day average, calculated from daily

averages, shows that the maximum 30 day rol ling 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/publ ications/proceedings/06/ecc/pdfs/Li cata.pdf; LG&E Energy, Selective

Catalytic Reduction: From Planning to Operation, Competitive Po wer 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 Works hop on SCR, October 19-20, 2004. Available here:

http://www.babcockpowe r.com/pdf/t-197.pdf.



# 32

# 33 . Further, permits have been issued to new coal-fired units that include NO X



# emission limits of 0.05 lb/MMBtu. These include:

• 0.035 lb/MMBtu 365-day rolling averag e, 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 rolli ng, 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 achi eved for such technology, this usually is

sufficient justification for you to assume the technical feas ibility of that technology or

emissions limit." 148 

# Spruce and Dallman are operating and meeting their permit limits.

In addition, Florida Power and Light f iled an application in March 2007 for the

Glades facility with a NO X 

# 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, Bl ack Hills Corporation, Wygen 3, Permit No. CT4517, February 5, 2007.

145 

# Wyoming Department of Environmental Quality, Basi n 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 Station2San Juan Unit 13Capacity (MWg)3604Capacity (MWn)32756COST ANALYSIS B&VCOST ANALYSIS FOX78Cost Item7/11/2007Remarks/Cost BasisEscalationEscalationEscalationRevisions910/22/2010to Oct 2011to Oct 2011(percent)10/10/2010Adjusted to 2010 Dollars10($)(percent)($)($)1112CAPITAL COST13Direct Costs14Purchased equipment costs15Anhydrous Ammonia Injection System$437,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$473,7085.3$429,592Adjusted to use final contractaward and remove installation16Anhydrous Ammonia Vaporization System$436,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$472,6245.3$429,592Adjusted to use final contractaward and remove installation17Reactor Box, Breeching and Ductwork$4,005,900Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$4,454,5610.0$3,585,687Adjusted to use final contractaward and reduced by 10% toaccount for cheaper materials per10/21/10 Responses, p. 2.18Ductwork Expansion Joints$147,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor8.4$159,3485.3$131,483Adjusted to use one unit, removefreight, scaled using actual unitflow rates, and reduce cost by10% to account for lessexpensive materials ofconstruction.19Catalyst$2,557,000Catalyst volume determinedbased on unit size & Noxremoval, $6500/m3 of catalyst0$2,557,0000.0$0Annualized cost must be reportednet of replacement materials.Cost Manual, pdf 47, 486.20Sonic Horns$188,000Actual price from similarlysized unit, escalated to 2007dollars8.4$203,7925.3$149,526Final contract award21Elevator$1,236,000Actual price from similarlysized unit, escalated to 2007dollars8.4$1,339,8245.3$633,097Adjusted to use final contractreward and to remove installationfrom vendor quote22Structural Steel$4,881,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$5,427,6720.0$4,993,012Adjusted to use final contractaward and remove complexityfactor.23SCR Bypass$10,000,000Taken from another B&Vproject of similar size8.4$10,840,0005.3$0Not required for oil firing duringstartup24NOx Monitoring System$440,000Actual price from similarlysized unit, escalated to 2007dollars8.4$476,9605.3$269,901Adjusted to use final contractaward, to require 1 trainingsession for the station, and toremove maintenance contract25Electrical System Upgrade$378,000Actual price from similarlysized unit, escalated to 2007dollars8.4$409,75211.2$420,33626Auxiliary Electrical Equipment Requirements$6,400,000Estimated in the B&V10/22/10 Cost Analysis0$6,400,0000.0$1,472,000Adjusted to 23% of B&V estimate22San Juan Unit 127Instrumentation and Control System$279,000Actual price from similarlysized unit, escalated to 2007dollars8.4$302,4365.3$365,867Adjusted to use final contractaward and remove escalation.28Subtotal capital cost (CC)$31,384,900$33,517,677$12,880,09229Gross Receipt Tax$1,942,000(CC) X 6.2%$2,074,000$758,000Adjusted to remove elevatorcosts30Freight$1,569,000(CC)X 5.0%$1,676,000$323,000Adjusted to remove sonic horns,elevator, structural steel, N0xmonitoring system, I&C system.31Total purchased equipment cost (PEC)$34,896,000$37,268,000$13,961,0923233Direct installation costs34Foundation & supports$10,468,800(PEC) X 30.0%6.2$11,117,86635Handling & erection$10,468,800(PEC) X 30.0%6.2$11,117,86636Electrical$5,234,400(PEC) X 15.0%6.2$5,558,93337Piping$872,400(PEC) X 2.5%6.2$926,48938Insulation$3,489,600(PEC) X 10.0%6.2$3,705,95539Painting$348,960(PEC) X 1.0%6.2$370,59640Demolition$3,489,600(PEC) X10.0%6.2$3,705,95541Relocation$1,744,800(PEC) X5.0%6.2$1,852,97842Total direct installation costs (DIC)$36,117,360$38,356,6364.4$8,799,917(PEC) X 62%. Adjusted toremove instrumentation andcontrol system.4344Air preheater modifications$1,071,000Based on a budgetary quotereceived for the project8.4$1,160,9645.3$0Not required for SCR.45Balanced draft conversion$14,323,000Adjusted from a B&Vbalanced draft conversionproject based on differencesin scope8.4$15,526,1325.3$2,544,690Adjusted to 23% less fanmodifications B&V 10/22/10 CostAnalysis, Table 546Induced draft fans5.3$2,885,220FD & ID fans minus thepressurized furnace differential.B&V 10/22/10 Cost Analysis,Table 447Site preparation$2,000,000Contingency for siteunknowns, such asunderground utilities0$2,000,000$0Excessive contingencies perCost Manual, pdf 44, 486.48Buildings & enclosures$500,000Contingency for general sitebuilding requirements0$500,000$0Excessive contingencies perCost Manual, pdf 44, 486.49Total direct costs (DC) = (PEC) + (DIC)$88,907,000$94,812,000$28,190,9205051Indirect Costs52Engineering$6,223,490(DC) X7.0%$6,636,840$2,819,000(DC) X 10%, Engineering &Home Office Fees, Cost Manual,pdf 486, Table 2.532San Juan Unit 153Owner's cost$4,445,350(DC) X 5.0%$4,740,600$0Included in Engineering & HomeOffice Fees.54Construction management$8,890,700$9,481,200$055Construction indirect$22,507,920B&V labor market review6.2$23,903,4114.4$11,490,682Reduced to 60% total installationlabor56Start-up and spare parts$2,667,210(DC) X 3.0%$2,844,360$846,00057Performance test$200,000Based on other projects withsimilar emissions testingscope$200,000$200,00058Contingencies$17,781,400(DC)X 20.0%$18,962,400$1,410,000(DC) X 5%, Cost Manual, pdf486, Table 2.559Total indirect costs (IC)$62,716,000$66,769,000$16,765,6826061Interest During Construction (IDC)$16,853,000[(DC)+(IC)] X 7.41% 3 years(project time length X 1/2)$16,853,000$0Not permitted under Cost Manualapproach62Loss Generation during Outage (GEN)$15,667,0005 weeks and 0.06095 $/kWh12 weeks required for BDC,$15,667,000$0Not required637 weeks major outageavailable64Project Contingency$6,743,490(DC + IC) X 15%, Cost Manual,pdf 486, Table 2.5.6566Total Capital Investment67(TCI)=(DC)+(IC)+(IDC)+(GEN)$184,143,000$194,101,000$51,700,092Adjusted to include projectcontingency6869ANNUAL COST70Direct Annual Costs71Fixed annual costs72Operating labor$125,0001 FTE and 124,862 $/yearEstimated manpower level$125,000$0Cost Manual, pdf 48773Maintenance labor & materials$2,667,000(DC) X 3.0%$2,844,000$776,000TCI X 1.5%, Cost Manual, pdf487.74Yearly emissions testing$25,000Based on other projects withsimilar emissions testingscope$25,000$25,00075Catalyst activity testing$5,000Engineering estimate$5,000$5,00076Fly ash sampling and analysis$20,000Engineering estimate$20,000$20,00077Total fixed annual costs$2,842,000$3,019,000$826,0007879Variable annual costs80Reagent$911,000350 lb/hr and 700 $/ton B&VCalculated$911,000$593,159Ammonia cost reduced to$475/ton. Ammonia flow ratereduced by 0.23/0.24.81Auxiliary and ID fan power$1,496,0003,287 kW and 0.06095 $/kWhB&V Calculated$1,496,000$402,084Adjusted to 0.3% gross capacityand $0.050/kWh42San Juan Unit 182Catalyst replacement$426,00065 m3 and 6,500 $/m3 2 yrcatalyst replacement rate$426,000$160,438Volume adjusted to 85% of B&Vestimate, unit cost reduced to$6000/m3, and FWF = 0.4883Total variable annual costs$2,833,000$2,833,000$1,155,6818485Total direct annual costs (DAC)$5,675,000$5,852,000$1,981,6818687Indirect Annual Costs88Cost for capital recovery$17,936,000(TCI) X 9.74% CRF at 7.41%interest & 20 year life$18,905,000$4,166,000(TCI) x 8.059% CRF at 7%interest & 30 year life89Total indirect annual costs (IDAC)$17,936,000$18,905,000$4,166,0009091Total Annual Cost (TAC) = (DAC) + (IDAC)$23,611,000$24,757,000$6,147,6819293Emission Reductions(ton/yr)3,174B&V BART Analysis, TableES-23,1743,1749495Cost Effectiveness ($/ton)7,4397,8001,9379697Cost ($/kW)5125391449899100101102Interest Rate0.07103Lifetime30104CRF0.080652San Juan Unit 23Capacity (MWg)3504Capacity (MWn)31656COST ANALYSIS B&VCOST ANALYSIS FOX78Cost Item7/11/2007Remarks/Cost BasisEscalationEscalationEscalationRevisions910/22/2010to Oct 2011to Oct 2011(percent)10/10/2010Adjusted to 2010 Dollars10($)(percent)($)($)1112CAPITAL COST13Direct Costs14Purchased equipment costs15Anhydrous Ammonia Injection System$429,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$465,0365.3$422,392Adjusted to use final contractaward and remove installation16Anhydrous Ammonia Vaporization System$429,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$465,0365.3$422,392Adjusted to use final contractaward and remove installation17Reactor Box, Breeching and Ductwork$3,999,600Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$4,447,5550.0$3,585,687Adjusted to use final contractaward and reduced by 10% toaccount for cheaper materials per10/21/10 Responses, p. 2.18Ductwork Expansion Joints$147,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor8.4$159,3485.3$131,282Adjusted to use one unit, removefreight, scaled using actual unitflow rates, and reduce cost by10% to account for lessexpensive materials ofconstruction.19Catalyst$2,553,000Catalyst volume determinedbased on unit size & Noxremoval, $6500/m3 of catalyst0$2,553,0000.0$0Annualized cost must be reportednet of replacement materials.Cost Manual, pdf 47, 486.20Sonic Horns$188,000Actual price from similarlysized unit, escalated to 2007dollars8.4$203,7925.3$149,526Final contract award21Elevator$1,236,000Actual price from similarlysized unit, escalated to 2007dollars8.4$1,339,8245.3$633,097Adjusted to use final contractreward and to remove installationfrom vendor quote22Structural Steel$5,998,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$6,669,7760.0$4,909,327Adjusted to use final contractaward and remove complexityfactor.23SCR Bypass$10,000,000Taken from another B&Vproject of similar size8.4$10,840,0005.3$0Not required for oil firing duringstartup24NOx Monitoring System$440,000Actual price from similarlysized unit, escalated to 2007dollars8.4$476,9605.3$269,901Adjusted to use final contractaward, to require 1 trainingsession for the station, and toremove maintenance contract62San Juan Unit 225Electrical System Upgrade$372,000Actual price from similarlysized unit, escalated to 2007dollars8.4$403,24811.2$413,66426Auxiliary Electrical Equipment Requirements$6,400,000Estimated in the B&V10/22/10 Cost Analysis0$6,400,0000.0$1,472,000Adjusted to 23% of B&V estimate27Instrumentation and Control System$278,000Actual price from similarlysized unit, escalated to 2007dollars8.4$301,3525.3$359,735Adjusted to use final contractaward and remove escalation.28Subtotal capital cost (CC)$32,469,600$34,724,927$12,769,00229Gross Receipt Tax$2,009,000(CC) X 6.2%$2,149,000$751,000Adjusted to remove elevatorcosts30Freight$1,623,000(CC)X 5.0%$1,736,000$322,000Adjusted to remove sonic horns,elevator, structural steel, N0xmonitoring system, I&C system.31Total purchased equipment cost (PEC)$36,102,000$38,610,000$13,842,0023233Direct installation costs34Foundation & supports$10,830,600(PEC) X 30.0%6.2$11,502,09735Handling & erection$14,440,800(PEC) X 30.0%6.2$15,336,13036Electrical$5,415,300(PEC) X 15.0%6.2$5,751,04937Piping$902,550(PEC) X 2.5%6.2$958,50838Insulation$3,610,200(PEC) X 10.0%6.2$3,834,03239Painting$361,020(PEC) X 1.0%6.2$383,40340Demolition$3,610,200(PEC) X10.0%6.2$3,834,03241Relocation$1,805,100(PEC) X5.0%6.2$1,917,01642Total direct installation costs (DIC)$40,975,770$43,516,2684.4$8,726,802(PEC) X 62%. Adjusted toremove instrumentation andcontrol system.4344Air preheater modifications$1,071,000Based on a budgetary quotereceived for the project8.4$1,160,9645.3$0Not required for SCR.45Balanced draft conversion$14,323,000Adjusted from a B&Vbalanced draft conversionproject based on differencesin scope8.4$15,526,1325.3$2,544,690Adjusted to 23% less fanmodifications B&V 10/22/10 CostAnalysis, Table 546Induced draft fans5.3$2,885,220FD & ID fans minus thepressurized furnace differential.B&V 10/22/10 Cost Analysis,Table 447Site preparation$2,000,000Contingency for siteunknowns, such asunderground utilities0$2,000,000$0Excessive contingencies perCost Manual, pdf 44, 486.48Buildings & enclosures$500,000Contingency for general sitebuilding requirements0$500,000$0Excessive contingencies perCost Manual, pdf 44, 486.49Total direct costs (DC) = (PEC) + (DIC)$94,972,000$101,313,000$27,998,7145072San Juan Unit 251Indirect Costs52Engineering$6,648,040(DC) X7.0%$7,091,910$2,800,000(DC) X 10%, Engineering &Home Office Fees, Cost Manual,pdf 486, Table 2.553Owner's cost$4,748,600(DC) X 5.0%$5,065,650$0Included in Engineering & HomeOffice Fees.54Construction management$9,497,200(DC) X 10.0%$10,131,300$055Construction indirect$26,895,990B&V labor market review6.2$28,563,5414.4$13,834,044Reduced to 60% total installationlabor56Start-up and spare parts$2,849,160(DC) X 3.0%$3,039,390$840,00057Performance test$200,000Based on other projects withsimilar emissions testingscope$200,000$200,00058Contingencies$18,994,400(DC)X 20.0%$20,262,600$1,400,000(DC) X 5%, Cost Manual, pdf486, Table 2.559Total indirect costs (IC)$69,833,000$74,354,000$19,074,0446061Interest During Construction (IDC)$18,318,000[(DC)+(IC)] X 7.41% 3 years(project time length X 1/2)$18,318,000$0Not permitted under Cost Manualapproach62Loss Generation during Outage (GEN)$15,231,0005 weeks and 0.06095 $/kWh12 weeks required for BDC,$15,667,000$0Not required637 weeks major outageavailable64Project Contingency$7,060,914(DC + IC) X 15%, Cost Manual,pdf 486, Table 2.5.6566Total Capital Investment67(TCI)=(DC)+(IC)+(IDC)+(GEN)$198,354,000$209,652,000$54,133,672Adjusted to include projectcontingency6869ANNUAL COST70Direct Annual Costs71Fixed annual costs72Operating labor$125,0001 FTE and 124,862 $/yearEstimated manpower level$125,000$0Cost Manual, pdf 48773Maintenance labor & materials$2,849,000(DC) X 3.0%$3,039,000$812,000TCI X 1.5%, Cost Manual, pdf487.74Yearly emissions testing$25,000Based on other projects withsimilar emissions testingscope$25,000$25,00075Catalyst activity testing$5,000Engineering estimate$5,000$5,00076Fly ash sampling and analysis$20,000Engineering estimate$20,000$20,00077Total fixed annual costs$3,024,000$3,214,000$862,0007879Variable annual costs82San Juan Unit 280Reagent$906,000348 lb/hr and 700 $/ton B&VCalculated$906,000$589,770Ammonia cost reduced to$475/ton. Ammonia flow ratereduced by 0.23/0.24.81Auxiliary and ID fan power$1,492,0003,287 kW and 0.06095 $/kWhB&V Calculated$1,492,000$390,915Adjusted to 0.3% gross capacityand $0.050/kWh82Catalyst replacement$426,00065 m3 and 6,500 $/m3 2 yrcatalyst replacement rate$426,000$160,438Adjusted to 85% of B&Vestimate, unit cost reduced to$6000/m3, and FWF = 0.48.83Total variable annual costs$2,824,000$2,824,000$1,141,1238485Total direct annual costs (DAC)$5,848,000$6,038,000$2,003,1238687Indirect Annual Costs88Cost for capital recovery$19,320,000(TCI) X 9.74% CRF at 7.41%interest & 20 year life$20,420,000$4,362,000(TCI) x 8.059% CRF at 7%interest & 30 year life89Total indirect annual costs (IDAC)$19,320,000$20,420,000$4,362,0009091Total Annual Cost (TAC) = (DAC) + (IDAC)$25,168,000$26,458,000$6,365,1239293Emission Reductions(ton/yr)3,158B&V BART Analysis, TableES-23,1583,1589495Cost Effectiveness ($/ton)7,9708,3782,0169697Cost ($/kW)5675991559899100101102Interest Rate0.07103Lifetime30104CRF0.080692San Juan Unit 33Capacity (MWg)5444Capacity (MWn)49756COST ANALYSIS B&VCOST ANALYSIS FOX78Cost Item7/11/2007Remarks/Cost BasisEscalationEscalationEscalationRevisions910/22/2010to Oct 2011to Oct 2011(percent)10/10/2010Adjusted to 2010 Dollars10($)(percent)($)($)1112CAPITAL COST13Direct Costs14Purchased equipment costs15Anhydrous Ammonia Injection System$559,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$605,9565.3$550,344Adjusted to use final contractaward and remove installation16Anhydrous Ammonia Vaporization System$559,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$605,9565.3$550,344Adjusted to use final contractaward and remove installation17Reactor Box, Breeching and Ductwork$5,051,700Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$5,617,4900.0$3,585,687Adjusted to use final contractaward and reduced by 10% toaccount for cheaper materials per10/21/10 Responses, p. 2.18Ductwork Expansion Joints$185,500Scaled from B&V databasebased on flue gas flow, using0.6 scale factor8.4$201,0825.3$165,809Adjusted to use one unit, removefreight, scaled using actual unitflow rates, and reduce cost by10% to account for lessexpensive materials ofconstruction.19Catalyst$3,225,000Catalyst volume determinedbased on unit size & Noxremoval, $6500/m3 of catalyst0$3,225,0000.0$0Annualized cost must be reportednet of replacement materials.Cost Manual, pdf 47, 486.20Sonic Horns$188,000Actual price from similarlysized unit, escalated to 2007dollars8.4$203,7925.3$149,526Final contract award21Elevator$1,236,000Actual price from similarlysized unit, escalated to 2007dollars8.4$1,339,8245.3$633,097Adjusted to use final contractreward and to remove installationfrom vendor quote22Structural Steel$7,816,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor8.4$8,472,5440.0$6,396,471Adjusted to use final contractaward and remove complexityfactor.23SCR Bypass$10,000,000Taken from another B&Vproject of similar size11.2$11,120,0005.3$0Not required for oil firing duringstartup24NOx Monitoring System$440,000Actual price from similarlysized unit, escalated to 2007dollars8.4$476,9605.3$269,901Adjusted to use final contractaward, to require 1 trainingsession for the station, and toremove maintenance contract102San Juan Unit 325Electrical System Upgrade$484,000Actual price from similarlysized unit, escalated to 2007dollars8.4$524,65611.2$538,20826Auxiliary Electrical Equipment Requirements$8,350,000Estimated in the B&V10/22/10 Cost Analysis0$8,350,0000.0$1,503,000Adjusted to 18% of B&V estimate27Instrumentation and Control System$291,000Actual price from similarlysized unit, escalated to 2007dollars8.4$315,4445.3$468,707Adjusted to use final contractaward and remove escalation.28Subtotal capital cost (CC)$38,385,200$41,058,704$14,811,09329Gross Receipt Tax$2,375,000(CC) X 6.2%$2,541,000$877,000Adjusted to remove elevatorcosts30Freight$1,919,000(CC)X 5.0%$2,053,000$345,000Adjusted to remove sonic horns,elevator, structural steel, N0xmonitoring system, I&C system.31Total purchased equipment cost (PEC)$42,679,000$45,653,000$16,033,0933233Direct installation costs34Foundation & supports$12,803,700(PEC) X 30.0%6.2$13,597,52935Handling & erection$17,071,600(PEC) X 40.0%6.2$18,130,03936Electrical$6,401,850(PEC) X 15.0%6.2$6,798,76537Piping$1,066,975(PEC) X 2.5%6.2$1,133,12738Insulation$4,267,900(PEC) X 10.0%6.2$4,532,51039Painting$426,790(PEC) X 1.0%6.2$453,25140Demolition$4,267,900(PEC) X10.0%6.2$4,532,51041Relocation$2,133,950(PEC) X5.0%6.2$2,266,25542Total direct installation costs (DIC)$48,440,665$51,443,9864.4$10,074,516(PEC) X 62%. Adjusted toremove instrumentation andcontrol system.4344Air preheater modifications$5,090,000Based on a budgetary quotereceived for the project8.4$5,517,5605.3$0Not required for SCR.45Balanced draft conversion$18,714,000Adjusted from a B&Vbalanced draft conversionproject based on differencesin scope8.4$20,285,9765.3$2,478,804Adjusted to 18% less fanmodifications B&V 10/22/10 CostAnalysis, Table 546Induced draft fans5.3$4,275,180FD & ID fans minus thepressurized furnace differential.B&V 10/22/10 Cost Analysis,Table 547Site preparation$2,000,000Contingency for siteunknowns, such asunderground utilities0$2,000,000$0Excessive contingencies perCost Manual, pdf 44, 486.48Buildings & enclosures$500,000Contingency for general sitebuilding requirements0$500,000$0Excessive contingencies perCost Manual, pdf 44, 486.49Total direct costs (DC) = (PEC) + (DIC)$117,424,000$125,401,000$32,861,59350112San Juan Unit 351Indirect Costs52Engineering$8,219,680(DC) X7.0%$8,778,070$3,286,000(DC) X 10%, Engineering &Home Office Fees, Cost Manual,pdf 486, Table 2.553Owner's cost$5,871,200(DC) X 5.0%$6,270,050$0Included in Engineering & HomeOffice Fees.54Construction management$11,742,400(DC) X 10.0%$12,540,100$055Construction indirect$31,795,855B&V labor market review6.2$33,767,1984.4$15,971,947Reduced to 60% total installationlabor56Start-up and spare parts$3,522,720(DC) X 3.0%$3,762,030$986,00057Performance test$200,000Based on other projects withsimilar emissions testingscope$200,000$200,00058Contingencies$23,484,800(DC)X 20.0%$25,080,200$1,643,000(DC) X 5%, Cost Manual, pdf486, Table 2.559Total indirect costs (IC)$84,837,000$90,398,000$22,086,9476061Interest During Construction (IDC)$22,481,000[(DC)+(IC)] X 7.41% 3 years(project time length X 1/2)$22,481,000$0Not permitted under Cost Manualapproach62Loss Generation during Outage (GEN)$23,674,0005 weeks and 0.06095 $/kWh12 weeks required for BDC,$23,674,000$0Not required637 weeks major outageavailable64Project Contingency$8,242,281(DC + IC) X 15%, Cost Manual,pdf 486, Table 2.5.6566Total Capital Investment67(TCI)=(DC)+(IC)+(IDC)+(GEN)$248,416,000$261,954,000$63,190,821Adjusted to include projectcontingency6869ANNUAL COST70Direct Annual Costs71Fixed annual costs72Operating labor$125,0001 FTE and 124,862 $/yearEstimated manpower level$125,000$0Cost Manual, pdf 48773Maintenance labor & materials$3,523,000(DC) X 3.0%$3,762,000$948,000TCI X 1.5%, Cost Manual, pdf487.74Yearly emissions testing$25,000Based on other projects withsimilar emissions testingscope$25,000$25,00075Catalyst activity testing$5,000Engineering estimate$5,000$5,00076Fly ash sampling and analysis$20,000Engineering estimate$20,000$20,00077Total fixed annual costs$3,698,000$3,937,000$998,0007879Variable annual costs122San Juan Unit 380Reagent$1,415,000543 lb/hr and 700 $/ton B&VCalculated$1,415,000$920,244Ammonia cost reduced to$475/ton. Ammonia flow ratereduced by 0.23/0.24.81Auxiliary and ID fan power$2,194,0004,881 kW and 0.06095 $/kWhB&V Calculated$2,194,000$607,594Adjusted to 0.3% gross capacityand $0.050/kWh82Catalyst replacement$538,00083 m3 and 6,500 $/m3 2 yrcatalyst replacement rate$538,000$202,619Adjusted to 85% of B&Vestimate, unit cost reduced to$6000/m3, and FWF = 0.4883Total variable annual costs$4,147,000$4,147,000$1,730,4578485Total direct annual costs (DAC)$7,845,000$8,084,000$2,728,4578687Indirect Annual Costs88Cost for capital recovery$24,196,000(TCI) X 9.74% CRF at 7.41%interest & 20 year life$24,196,000$5,092,000(TCI) x 8.059% CRF at 7%interest & 30 year life89Total indirect annual costs (IDAC)$24,196,000$24,196,000$5,092,0009091Total Annual Cost (TAC) = (DAC) + (IDAC)$32,041,000$32,280,000$7,820,4579293Emission Reductions(ton/yr)4,931B&V BART Analysis, TableES-24,9314,9319495Cost Effectiveness ($/ton)6,4986,5461,5869697Cost ($/kW)4574821169899100101102Interest Rate0.07103Lifetime30104CRF0.0806132San Juan Unit 43Capacity (MWg)5444Capacity (MWn)50756COST ANALYSIS B&VCOST ANALYSIS FOX78Cost Item7/11/2007Remarks/Cost BasisEscalationEscalationEscalationRevisions910/22/2010to Oct 2011to Oct 2011(percent)10/10/2010Adjusted to 2010 Dollars10($)(percent)($)($)1112CAPITAL COST13Direct Costs14Purchased equipment costs15Anhydrous Ammonia Injection System$559,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$605,9565.3$550,344Adjusted to use final contractaward and remove installation16Anhydrous Ammonia Vaporization System$559,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$605,9565.3$550,344Adjusted to use final contractaward and remove installation17Reactor Box, Breeching and Ductwork$5,083,200Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$5,652,5180.0$3,585,687Adjusted to use final contractaward and reduced by 10% toaccount for cheaper materials per10/21/10 Responses, p. 2.18Ductwork Expansion Joints$186,500Scaled from B&V databasebased on flue gas flow, using0.6 scale factor8.4$202,1665.3$166,853Adjusted to use one unit, removefreight, scaled using actual unitflow rates, and reduce cost by10% to account for lessexpensive materials ofconstruction.19Catalyst$3,245,000Catalyst volume determinedbased on unit size & Noxremoval, $6500/m3 of catalyst0$3,245,0000.0$0Annualized cost must be reportednet of replacement materials.Cost Manual, pdf 47, 486.20Sonic Horns$188,000Actual price from similarlysized unit, escalated to 2007dollars8.4$203,7925.3$149,526Final contract award21Elevator$1,236,000Actual price from similarlysized unit, escalated to 2007dollars8.4$1,339,8245.3$633,097Adjusted to use final contractreward and to remove installationfrom vendor quote22Structural Steel$6,252,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$6,952,2240.0$6,396,471Adjusted to use final contractaward and remove complexityfactor.23SCR Bypass$10,000,000Taken from another B&Vproject of similar size8.4$10,840,0005.3$0Not required for oil firing duringstartup24NOx Monitoring System$440,000Actual price from similarlysized unit, escalated to 2007dollars8.4$476,9605.3$269,901Adjusted to use final contractaward, to require 1 trainingsession for the station, and toremove maintenance contract142San Juan Unit 425Electrical System Upgrade$484,000Actual price from similarlysized unit, escalated to 2007dollars8.4$524,65611.2$538,20826Auxiliary Electrical Equipment Requirements$8,350,000Estimated in the B&V10/22/10 Cost Analysis0$8,350,0000.0$1,503,000Adjusted to 18% of B&V estimate27Instrumentation and Control System$291,000Actual price from similarlysized unit, escalated to 2007dollars8.4$315,4445.3$468,707Adjusted to use final contractaward and remove escalation.28Subtotal capital cost (CC)$36,873,700$39,314,496$14,812,13729Gross Receipt Tax$2,282,000(CC) X 6.2%$2,433,000$877,000Adjusted to remove elevatorcosts30Freight$1,844,000(CC)X 5.0%$1,966,000$345,000Adjusted to remove sonic horns,elevator, structural steel, N0xmonitoring system, I&C system.31Total purchased equipment cost (PEC)$41,000,000$43,713,496$16,034,1373233Direct installation costs34Foundation & supports$12,300,000(PEC) X 30.0%6.2$13,062,60035Handling & erection$12,300,000(PEC) X 30.0%6.2$13,062,60036Electrical$6,150,000(PEC) X 15.0%6.2$6,531,30037Piping$1,025,000(PEC) X 2.5%6.2$1,088,55038Insulation$4,100,000(PEC) X 10.0%6.2$4,354,20039Painting$410,000(PEC) X 1.0%6.2$435,42040Demolition$4,100,000(PEC) X10.0%6.2$4,354,20041Relocation$2,050,000(PEC) X5.0%6.2$2,177,10042Total direct installation costs (DIC)$42,435,000$45,065,9704.4$10,075,191(PEC) X 62%. Adjusted toremove instrumentation andcontrol system.4344Air preheater modifications$5,090,000Based on a budgetary quotereceived for the project8.4$5,517,5605.3$0Not required for SCR.45Balanced draft conversion$18,714,000Adjusted from a B&Vbalanced draft conversionproject based on differencesin scope8.4$20,285,9765.3$2,478,804Adjusted to 18% less fanmodifications B&V 10/22/10 CostAnalysis, Table 546Induced draft fans5.3$4,275,180FD & ID fans minus thepressurized furnace differential.B&V 10/22/10 Cost Analysis,Table 5.47Site preparation$2,000,000Contingency for siteunknowns, such asunderground utilities0$2,000,000$0Excessive contingencies perCost Manual, pdf 44, 486.48Buildings & enclosures$500,000Contingency for general sitebuilding requirements0$500,000$0Excessive contingencies perCost Manual, pdf 44, 486.49Total direct costs (DC) = (PEC) + (DIC)$109,739,000$117,083,000$32,863,31250152San Juan Unit 451Indirect Costs52Engineering$7,682,000(DC) X7.0%$8,195,810$3,286,000(DC) X 10%, Engineering &Home Office Fees, Cost Manual,pdf 486, Table 2.553Owner's cost$5,487,000(DC) X 5.0%$5,854,150$0Included in Engineering & HomeOffice Fees.54Construction management$10,974,000(DC) X 10.0%$11,708,300$055Construction indirect$26,445,000B&V labor market review6.2$28,084,5904.4$13,151,894Reduced to 60% total installationlabor56Start-up and spare parts$3,292,000(DC) X 3.0%$3,512,000$986,00057Performance test$200,000Based on other projects withsimilar emissions testingscope$200,000$200,00058Contingencies$21,948,000(DC)X 20.0%$23,416,600$1,643,000(DC) X 5%, Cost Manual, pdf486, Table 2.559Total indirect costs (IC)$76,028,000$80,972,000$19,266,8946061Interest During Construction (IDC)$20,648,000[(DC)+(IC)] X 7.41% 3 years(project time length X 1/2)$20,648,000$0Not permitted under Cost Manualapproach62Loss Generation during Outage (GEN)$23,674,0005 weeks and 0.06095 $/kWh12 weeks required for BDC,$23,674,000$0Not required637 weeks major outageavailable64Project Contingency$7,819,531(DC + IC) X 15%, Cost Manual,pdf 486, Table 2.5.6566Total Capital Investment67(TCI)=(DC)+(IC)+(IDC)+(GEN)$230,089,000$242,377,000$59,949,738Adjusted to include projectcontingency6869ANNUAL COST70Direct Annual Costs71Fixed annual costs72Operating labor$125,0001 FTE and 124,862 $/yearEstimated manpower level$125,000$0Cost Manual, pdf 48773Maintenance labor & materials$3,292,000(DC) X 3.0%$3,512,000$899,000TCI X 1.5%, Cost Manual, pdf487.74Yearly emissions testing$25,000Based on other projects withsimilar emissions testingscope$25,000$25,00075Catalyst activity testing$5,000Engineering estimate$5,000$5,00076Fly ash sampling and analysis$20,000Engineering estimate$20,000$20,00077Total fixed annual costs$3,467,000$3,687,000$949,0007879Variable annual costs162San Juan Unit 480Reagent$1,388,000533 lb/hr and 700 $/ton B&VCalculated$1,388,000$903,297Ammonia cost reduced to$475/ton. Ammonia flow ratereduced by 0.23/0.24.81Auxiliary and ID fan power$2,215,0004,881 kW and 0.06095 $/kWhB&V Calculated$2,215,000$607,594Adjusted to 0.3% gross capacityand $0.050/kWh82Catalyst replacement$541,00083 m3 and 6,500 $/m3 2 yrcatalyst replacement rate$541,000$203,749Adjusted to 85% of B&Vestimate, unit cost reduced to$6000/m3, and FWF = 0.48.83Total variable annual costs$4,144,000$4,144,000$1,714,6398485Total direct annual costs (DAC)$7,611,000$7,831,000$2,663,6398687Indirect Annual Costs88Cost for capital recovery$22,411,000(TCI) X 9.74% CRF at 7.41%interest & 20 year life$22,411,000$4,831,000(TCI) x 8.059% CRF at 7%interest & 30 year life89Total indirect annual costs (IDAC)$22,411,000$22,411,000$4,831,0009091Total Annual Cost (TAC) = (DAC) + (IDAC)$30,022,000$30,242,000$7,494,6399293Emission Reductions(ton/yr)4,837B&V BART Analysis, TableES-24,8374,8379495Cost Effectiveness ($/ton)6,2076,2521,5499697Cost ($/kW)4234461109899100101102Interest Rate0.07103Lifetime30104CRF0.0806172San Juan Unit 1 @ 0.05 lbs/MMBtu3Capacity (MWg)3604Capacity (MWn)32756COST ANALYSIS B&VCOST ANALYSIS FOX78Cost Item7/11/2007Remarks/Cost BasisEscalationEscalationEscalationRevisions910/22/2010to Oct 2011to Oct 2011(percent)10/10/2010Adjusted to 2010 Dollars10($)(percent)($)($)1112CAPITAL COST13Direct Costs14Purchased equipment costs15Anhydrous Ammonia Injection System$437,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$473,7085.3$429,592Adjusted to use final contractaward and remove installation16Anhydrous Ammonia Vaporization System$436,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$472,6245.3$429,592Adjusted to use final contractaward and remove installation17Reactor Box, Breeching and Ductwork$4,005,900Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$4,454,5610.0$3,585,687Adjusted to use final contractaward and reduced by 10% toaccount for cheaper materials per10/21/10 Responses, p. 2.18Ductwork Expansion Joints$147,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor8.4$159,3485.3$131,483Adjusted to use one unit, removefreight, scaled using actual unitflow rates, and reduce cost by10% to account for lessexpensive materials ofconstruction.19Catalyst$2,557,000Catalyst volume determinedbased on unit size & Noxremoval, $6500/m3 of catalyst0$2,557,0000.0$0Annualized cost must be reportednet of replacement materials.Cost Manual, pdf 47, 486.20Sonic Horns$188,000Actual price from similarlysized unit, escalated to 2007dollars8.4$203,7925.3$149,526Final contract award21Elevator$1,236,000Actual price from similarlysized unit, escalated to 2007dollars8.4$1,339,8245.3$633,097Adjusted to use final contractreward and to remove installationfrom vendor quote22Structural Steel$4,881,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$5,427,6720.0$4,993,012Adjusted to use final contractaward and remove complexityfactor.23SCR Bypass$10,000,000Taken from another B&Vproject of similar size8.4$10,840,0005.3$0Not required for oil firing duringstartup24NOx Monitoring System$440,000Actual price from similarlysized unit, escalated to 2007dollars8.4$476,9605.3$269,901Adjusted to use final contractaward, to require 1 trainingsession for the station, and toremove maintenance contract182San Juan Unit 1 @ 0.05 lbs/MMBtu25Electrical System Upgrade$378,000Actual price from similarlysized unit, escalated to 2007dollars8.4$409,75211.2$420,33626Auxiliary Electrical Equipment Requirements$6,400,000Estimated in the B&V10/22/10 Cost Analysis0$6,400,0000.0$1,472,000Adjusted to 23% of B&V estimate27Instrumentation and Control System$279,000Actual price from similarlysized unit, escalated to 2007dollars8.4$302,4365.3$365,867Adjusted to use final contractaward and remove escalation.28Subtotal capital cost (CC)$31,384,900$33,517,677$12,880,09229Gross Receipt Tax$1,942,000(CC) X 6.2%$2,074,000$758,000Adjusted to remove elevatorcosts30Freight$1,569,000(CC)X 5.0%$1,676,000$323,000Adjusted to remove sonic horns,elevator, structural steel, N0xmonitoring system, I&C system.31Total purchased equipment cost (PEC)$34,896,000$37,268,000$13,961,0923233Direct installation costs34Foundation & supports$10,468,800(PEC) X 30.0%6.2$11,117,86635Handling & erection$10,468,800(PEC) X 30.0%6.2$11,117,86636Electrical$5,234,400(PEC) X 15.0%6.2$5,558,93337Piping$872,400(PEC) X 2.5%6.2$926,48938Insulation$3,489,600(PEC) X 10.0%6.2$3,705,95539Painting$348,960(PEC) X 1.0%6.2$370,59640Demolition$3,489,600(PEC) X10.0%6.2$3,705,95541Relocation$1,744,800(PEC) X5.0%6.2$1,852,97842Total direct installation costs (DIC)$36,117,360$38,356,6364.4$8,799,917(PEC) X 62%. Adjusted toremove instrumentation andcontrol system.4344Air preheater modifications$1,071,000Based on a budgetary quotereceived for the project8.4$1,160,9645.3$0Not required for SCR.45Balanced draft conversion$14,323,000Adjusted from a B&Vbalanced draft conversionproject based on differencesin scope8.4$15,526,1325.3$2,544,690Adjusted to 23% less fanmodifications B&V 10/22/10 CostAnalysis, Table 546Induced draft fans5.3$2,885,220FD & ID fans minus thepressurized furnace differential.B&V 10/22/10 Cost Analysis,Table 447Site preparation$2,000,000Contingency for siteunknowns, such asunderground utilities0$2,000,000$0Excessive contingencies perCost Manual, pdf 44, 486.48Buildings & enclosures$500,000Contingency for general sitebuilding requirements0$500,000$0Excessive contingencies perCost Manual, pdf 44, 486.49Total direct costs (DC) = (PEC) + (DIC)$88,907,000$94,812,000$28,190,92050192San Juan Unit 1 @ 0.05 lbs/MMBtu51Indirect Costs52Engineering$6,223,490(DC) X7.0%$6,636,840$2,819,000(DC) X 10%, Engineering &Home Office Fees, Cost Manual,pdf 486, Table 2.553Owner's cost$4,445,350(DC) X 5.0%$4,740,600$0Included in Engineering & HomeOffice Fees.54Construction management$8,890,700(DC) X 10.0%$9,481,200$055Construction indirect$22,507,920B&V labor market review6.2$23,903,4114.4$11,490,682Reduced to 60% total installationlabor56Start-up and spare parts$2,667,210(DC) X 3.0%$2,844,360$846,00057Performance test$200,000Based on other projects withsimilar emissions testingscope$200,000$200,00058Contingencies$17,781,400(DC)X 20.0%$18,962,400$1,410,000(DC) X 5%, Cost Manual, pdf486, Table 2.559Total indirect costs (IC)$62,716,000$66,769,000$16,765,6826061Interest During Construction (IDC)$16,853,000[(DC)+(IC)] X 7.41% 3 years(project time length X 1/2)$16,853,000$0Not permitted under Cost Manualapproach62Loss Generation during Outage (GEN)$15,667,0005 weeks and 0.06095 $/kWh12 weeks required for BDC,$15,667,000$0Not required637 weeks major outageavailable64Project Contingency$6,743,490(DC + IC) X 15%, Cost Manual,pdf 486, Table 2.5.6566Total Capital Investment67(TCI)=(DC)+(IC)+(IDC)+(GEN)$184,143,000$194,101,000$51,700,092Adjusted to include projectcontingency6869ANNUAL COST70Direct Annual Costs71Fixed annual costs72Operating labor$125,0001 FTE and 124,862 $/yearEstimated manpower level$125,000$0Cost Manual, pdf 48773Maintenance labor & materials$2,667,000(DC) X 3.0%$2,844,000$776,000TCI X 1.5%, Cost Manual, pdf487.74Yearly emissions testing$25,000Based on other projects withsimilar emissions testingscope$25,000$25,00075Catalyst activity testing$5,000Engineering estimate$5,000$5,00076Fly ash sampling and analysis$20,000Engineering estimate$20,000$20,00077Total fixed annual costs$2,842,000$3,019,000$826,0007879Variable annual costs202San Juan Unit 1 @ 0.05 lbs/MMBtu80Reagent$911,000350 lb/hr and 700 $/ton B&VCalculated$911,000$644,738Ammonia cost reduced to$475/ton. Ammonia flow rateincreased by 0.25/0.24.81Auxiliary and ID fan power$1,496,0003,287 kW and 0.06095 $/kWhB&V Calculated$1,496,000$402,084Adjusted to 0.3% gross capacityand $0.050/kWh82Catalyst replacement$426,00065 m3 and 6,500 $/m3 2 yrcatalyst replacement rate$426,000$188,751B&V assumed a catalyst volumesufficient to reduce NOx from 0.3to 0.044 lb/MMBtu, so adequatefor 0.05. Unit cost reduced to6000/m3 and FWF = 0.48.83Total variable annual costs$2,833,000$2,833,000$1,235,5738485Total direct annual costs (DAC)$5,675,000$5,852,000$2,061,5738687Indirect Annual Costs88Cost for capital recovery$17,936,000(TCI) X 9.74% CRF at 7.41%interest & 20 year life$18,905,000$4,166,000(TCI) x 8.059% CRF at 7%interest & 30 year life89Total indirect annual costs (IDAC)$17,936,000$18,905,000$4,166,0009091Total Annual Cost (TAC) = (DAC) + (IDAC)$23,611,000$24,757,000$6,227,5739293Emission Reductions(ton/yr)3,174B&V BART Analysis, TableES-23,1743,450Increased tons NOx reduced by(0.25/0.23) for outlet of 0.05lbs/MMBtu9495Cost Effectiveness ($/ton)7,4397,8001,8059697Cost ($/kW)5125391449899100101102Interest Rate0.07103Lifetime30104CRF0.0806212San Juan Unit 2 @ 0.05 lbs/MMBtu3Capacity (MWg)3504Capacity (MWn)31656COST ANALYSIS B&VCOST ANALYSIS FOX78Cost Item7/11/2007Remarks/Cost BasisEscalationEscalationEscalationRevisions910/22/2010to Oct 2011to Oct 2011(percent)10/10/2010Adjusted to 2010 Dollars10($)(percent)($)($)1112CAPITAL COST13Direct Costs14Purchased equipment costs15Anhydrous Ammonia Injection System$429,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$465,0365.3$422,392Adjusted to use final contractaward and remove installation16Anhydrous Ammonia Vaporization System$429,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$465,0365.3$422,392Adjusted to use final contractaward and remove installation17Reactor Box, Breeching and Ductwork$3,999,600Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$4,447,5550.0$3,585,687Adjusted to use final contractaward and reduced by 10% toaccount for cheaper materials per10/21/10 Responses, p. 2.18Ductwork Expansion Joints$147,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor8.4$159,3485.3$131,282Adjusted to use one unit, removefreight, scaled using actual unitflow rates, and reduce cost by10% to account for lessexpensive materials ofconstruction.19Catalyst$2,553,000Catalyst volume determinedbased on unit size & Noxremoval, $6500/m3 of catalyst0$2,553,0000.0$0Annualized cost must be reportednet of replacement materials.Cost Manual, pdf 47, 486.20Sonic Horns$188,000Actual price from similarlysized unit, escalated to 2007dollars8.4$203,7925.3$149,526Final contract award21Elevator$1,236,000Actual price from similarlysized unit, escalated to 2007dollars8.4$1,339,8245.3$633,097Adjusted to use final contractreward and to remove installationfrom vendor quote22Structural Steel$5,998,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$6,669,7760.0$4,909,327Adjusted to use final contractaward and remove complexityfactor.23SCR Bypass$10,000,000Taken from another B&Vproject of similar size8.4$10,840,0005.3$0Not required for oil firing duringstartup24NOx Monitoring System$440,000Actual price from similarlysized unit, escalated to 2007dollars8.4$476,9605.3$269,901Adjusted to use final contractaward, to require 1 trainingsession for the station, and toremove maintenance contract222San Juan Unit 2 @ 0.05 lbs/MMBtu25Electrical System Upgrade$372,000Actual price from similarlysized unit, escalated to 2007dollars8.4$403,24811.2$413,66426Auxiliary Electrical Equipment Requirements$6,400,000Estimated in the B&V10/22/10 Cost Analysis0$6,400,0000.0$1,472,000Adjusted to 23% of B&V estimate27Instrumentation and Control System$278,000Actual price from similarlysized unit, escalated to 2007dollars8.4$301,3525.3$359,735Adjusted to use final contractaward and remove escalation.28Subtotal capital cost (CC)$32,469,600$34,724,927$12,769,00229Gross Receipt Tax$2,009,000(CC) X 6.2%$2,149,000$751,000Adjusted to remove elevatorcosts30Freight$1,623,000(CC)X 5.0%$1,736,000$322,000Adjusted to remove sonic horns,elevator, structural steel, N0xmonitoring system, I&C system.31Total purchased equipment cost (PEC)$36,102,000$38,610,000$13,842,0023233Direct installation costs34Foundation & supports$10,830,600(PEC) X 30.0%6.2$11,502,09735Handling & erection$14,440,800(PEC) X 30.0%6.2$15,336,13036Electrical$5,415,300(PEC) X 15.0%6.2$5,751,04937Piping$902,550(PEC) X 2.5%6.2$958,50838Insulation$3,610,200(PEC) X 10.0%6.2$3,834,03239Painting$361,020(PEC) X 1.0%6.2$383,40340Demolition$3,610,200(PEC) X10.0%6.2$3,834,03241Relocation$1,805,100(PEC) X5.0%6.2$1,917,01642Total direct installation costs (DIC)$40,975,770$43,516,2684.4$8,726,802(PEC) X 62%. Adjusted toremove instrumentation andcontrol system.4344Air preheater modifications$1,071,000Based on a budgetary quotereceived for the project8.4$1,160,9645.3$0Not required for SCR.45Balanced draft conversion$14,323,000Adjusted from a B&Vbalanced draft conversionproject based on differencesin scope8.4$15,526,1325.3$2,544,690Adjusted to 23% less fanmodifications B&V 10/22/10 CostAnalysis, Table 546Induced draft fans5.3$2,885,220FD & ID fans minus thepressurized furnace differential.B&V 10/22/10 Cost Analysis,Table 447Site preparation$2,000,000Contingency for siteunknowns, such asunderground utilities0$2,000,000$0Excessive contingencies perCost Manual, pdf 44, 486.48Buildings & enclosures$500,000Contingency for general sitebuilding requirements0$500,000$0Excessive contingencies perCost Manual, pdf 44, 486.49Total direct costs (DC) = (PEC) + (DIC)$94,972,000$101,313,000$27,998,71450232San Juan Unit 2 @ 0.05 lbs/MMBtu51Indirect Costs52Engineering$6,648,040(DC) X7.0%$7,091,910$2,800,000(DC) X 10%, Engineering &Home Office Fees, Cost Manual,pdf 486, Table 2.553Owner's cost$4,748,600(DC) X 5.0%$5,065,650$0Included in Engineering & HomeOffice Fees.54Construction management$9,497,200(DC) X 10.0%$10,131,300$055Construction indirect$26,895,990B&V labor market review6.2$28,563,5414.4$13,834,044Reduced to 60% total installationlabor56Start-up and spare parts$2,849,160(DC) X 3.0%$3,039,390$840,00057Performance test$200,000Based on other projects withsimilar emissions testingscope$200,000$200,00058Contingencies$18,994,400(DC)X 20.0%$20,262,600$1,400,000(DC) X 5%, Cost Manual, pdf486, Table 2.559Total indirect costs (IC)$69,833,000$74,354,000$19,074,0446061Interest During Construction (IDC)$18,318,000[(DC)+(IC)] X 7.41% 3 years(project time length X 1/2)$18,318,000$0Not permitted under Cost Manualapproach62Loss Generation during Outage (GEN)$15,231,0005 weeks and 0.06095 $/kWh12 weeks required for BDC,$15,667,000$0Not required637 weeks major outageavailable64Project Contingency$7,060,914(DC + IC) X 15%, Cost Manual,pdf 486, Table 2.5.6566Total Capital Investment67(TCI)=(DC)+(IC)+(IDC)+(GEN)$198,354,000$209,652,000$54,133,672Adjusted to include projectcontingency6869ANNUAL COST70Direct Annual Costs71Fixed annual costs72Operating labor$125,0001 FTE and 124,862 $/yearEstimated manpower level$125,000$0Cost Manual, pdf 48773Maintenance labor & materials$2,849,000(DC) X 3.0%$3,039,000$812,000TCI X 1.5%, Cost Manual, pdf487.74Yearly emissions testing$25,000Based on other projects withsimilar emissions testingscope$25,000$25,00075Catalyst activity testing$5,000Engineering estimate$5,000$5,00076Fly ash sampling and analysis$20,000Engineering estimate$20,000$20,00077Total fixed annual costs$3,024,000$3,214,000$862,0007879Variable annual costs242San Juan Unit 2 @ 0.05 lbs/MMBtu80Reagent$906,000348 lb/hr and 700 $/ton B&VCalculated$906,000$641,054Ammonia cost reduced to$475/ton. Ammonia flow rateincreased by 0.25/0.24.81Auxiliary and ID fan power$1,492,0003,287 kW and 0.06095 $/kWhB&V Calculated$1,492,000$390,915Adjusted to 0.3% gross capacityand $0.050/kWh82Catalyst replacement$426,00065 m3 and 6,500 $/m3 2 yrcatalyst replacement rate$426,000$188,751B&V assumed a catalyst volumesufficient to reduce NOx from 0.3to 0.044 lb/MMBtu, so adequatefor 0.05. Unit cost reduced to$6000/m3 and FWF = 0.48.83Total variable annual costs$2,824,000$2,824,000$1,220,7208485Total direct annual costs (DAC)$5,848,000$6,038,000$2,082,7208687Indirect Annual Costs88Cost for capital recovery$19,320,000(TCI) X 9.74% CRF at 7.41%interest & 20 year life$20,420,000$4,362,000(TCI) x 8.059% CRF at 7%interest & 30 year life89Total indirect annual costs (IDAC)$19,320,000$20,420,000$4,362,0009091Total Annual Cost (TAC) = (DAC) + (IDAC)$25,168,000$26,458,000$6,444,7209293Emission Reductions(ton/yr)3,158B&V BART Analysis, TableES-23,1583,433Increased tons NOx reduced by(0.25/0.23) for outlet of 0.05lbs/MMBtu9495Cost Effectiveness ($/ton)7,9708,3781,8779697Cost ($/kW)5675991559899100101102Interest Rate0.07103Lifetime30104CRF0.080625San Juan Unit 3 @ 0.05 lbs/MMBtu23Capacity (MWg)5444Capacity (MWn)49756COST ANALYSIS B&VCOST ANALYSIS FOX78Cost Item7/11/2007Remarks/Cost BasisEscalationEscalationEscalationRevisions910/22/2010to Oct 2011to Oct 2011(percent)10/10/2010Adjusted to 2010 Dollars10($)(percent)($)($)1112CAPITAL COST13Direct Costs14Purchased equipment costs15Anhydrous Ammonia Injection System$559,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$605,9565.3$550,344Adjusted to use final contractaward and remove installation16Anhydrous Ammonia Vaporization System$559,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$605,9565.3$550,344Adjusted to use final contractaward and remove installation17Reactor Box, Breeching and Ductwork$5,051,700Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$5,617,4900.0$3,585,687Adjusted to use final contractaward and reduced by 10% toaccount for cheaper materials per10/21/10 Responses, p. 2.18Ductwork Expansion Joints$185,500Scaled from B&V databasebased on flue gas flow, using0.6 scale factor8.4$201,0825.3$165,809Adjusted to use one unit, removefreight, scaled using actual unitflow rates, and reduce cost by10% to account for lessexpensive materials ofconstruction.19Catalyst$3,225,000Catalyst volume determinedbased on unit size & Noxremoval, $6500/m3 of catalyst0$3,225,0000.0$0Annualized cost must be reportednet of replacement materials.Cost Manual, pdf 47, 486.20Sonic Horns$188,000Actual price from similarlysized unit, escalated to 2007dollars8.4$203,7925.3$149,526Final contract award21Elevator$1,236,000Actual price from similarlysized unit, escalated to 2007dollars8.4$1,339,8245.3$633,097Adjusted to use final contractreward and to remove installationfrom vendor quote22Structural Steel$7,816,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor8.4$8,472,5440.0$6,396,471Adjusted to use final contractaward and remove complexityfactor.23SCR Bypass$10,000,000Taken from another B&Vproject of similar size11.2$11,120,0005.3$0Not required for oil firing duringstartup24NOx Monitoring System$440,000Actual price from similarlysized unit, escalated to 2007dollars8.4$476,9605.3$269,901Adjusted to use final contractaward, to require 1 trainingsession for the station, and toremove maintenance contract262San Juan Unit 3 @ 0.05 lbs/MMBtu25Electrical System Upgrade$484,000Actual price from similarlysized unit, escalated to 2007dollars8.4$524,65611.2$538,20826Auxiliary Electrical Equipment Requirements$8,350,000Estimated in the B&V10/22/10 Cost Analysis0$8,350,0000.0$1,503,000Adjusted to 18% of B&V estimate27Instrumentation and Control System$291,000Actual price from similarlysized unit, escalated to 2007dollars8.4$315,4445.3$468,707Adjusted to use final contractaward and remove escalation.28Subtotal capital cost (CC)$38,385,200$41,058,704$14,811,09329Gross Receipt Tax$2,375,000(CC) X 6.2%$2,541,000$877,000Adjusted to remove elevatorcosts30Freight$1,919,000(CC)X 5.0%$2,053,000$345,000Adjusted to remove sonic horns,elevator, structural steel, N0xmonitoring system, I&C system.31Total purchased equipment cost (PEC)$42,679,000$45,653,000$16,033,0933233Direct installation costs34Foundation & supports$12,803,700(PEC) X 30.0%6.2$13,597,52935Handling & erection$17,071,600(PEC) X 40.0%6.2$18,130,03936Electrical$6,401,850(PEC) X 15.0%6.2$6,798,76537Piping$1,066,975(PEC) X 2.5%6.2$1,133,12738Insulation$4,267,900(PEC) X 10.0%6.2$4,532,51039Painting$426,790(PEC) X 1.0%6.2$453,25140Demolition$4,267,900(PEC) X10.0%6.2$4,532,51041Relocation$2,133,950(PEC) X5.0%6.2$2,266,25542Total direct installation costs (DIC)$48,440,665$51,443,9864.4$10,074,516(PEC) X 62%. Adjusted toremove instrumentation andcontrol system.4344Air preheater modifications$5,090,000Based on a budgetary quotereceived for the project8.4$5,517,5605.3$0Not required for SCR.45Balanced draft conversion$18,714,000Adjusted from a B&Vbalanced draft conversionproject based on differencesin scope8.4$20,285,9765.3$2,478,804Adjusted to 18% less fanmodifications B&V 10/22/10 CostAnalysis, Table 546Induced draft fans5.3$4,275,180FD & ID fans minus thepressurized furnace differential.B&V 10/22/10 Cost Analysis,Table 547Site preparation$2,000,000Contingency for siteunknowns, such asunderground utilities0$2,000,000$0Excessive contingencies perCost Manual, pdf 44, 486.48Buildings & enclosures$500,000Contingency for general sitebuilding requirements0$500,000$0Excessive contingencies perCost Manual, pdf 44, 486.49Total direct costs (DC) = (PEC) + (DIC)$117,424,000$125,401,000$32,861,59350272San Juan Unit 3 @ 0.05 lbs/MMBtu51Indirect Costs52Engineering$8,219,680(DC) X7.0%$8,778,070$3,286,000(DC) X 10%, Engineering &Home Office Fees, Cost Manual,pdf 486, Table 2.553Owner's cost$5,871,200(DC) X 5.0%$6,270,050$0Included in Engineering & HomeOffice Fees.54Construction management$11,742,400(DC) X 10.0%$12,540,100$055Construction indirect$31,795,855B&V labor market review6.2$33,767,1984.4$15,971,947Reduced to 60% total installationlabor56Start-up and spare parts$3,522,720(DC) X 3.0%$3,762,030$986,00057Performance test$200,000Based on other projects withsimilar emissions testingscope$200,000$200,00058Contingencies$23,484,800(DC)X 20.0%$25,080,200$1,643,000(DC) X 5%, Cost Manual, pdf486, Table 2.559Total indirect costs (IC)$84,837,000$90,398,000$22,086,9476061Interest During Construction (IDC)$22,481,000[(DC)+(IC)] X 7.41% 3 years(project time length X 1/2)$22,481,000$0Not permitted under Cost Manualapproach62Loss Generation during Outage (GEN)$23,674,0005 weeks and 0.06095 $/kWh12 weeks required for BDC,$23,674,000$0Not required637 weeks major outageavailable64Project Contingency$8,242,281(DC + IC) X 15%, Cost Manual,pdf 486, Table 2.5.6566Total Capital Investment67(TCI)=(DC)+(IC)+(IDC)+(GEN)$248,416,000$261,954,000$63,190,821Adjusted to include projectcontingency6869ANNUAL COST70Direct Annual Costs71Fixed annual costs72Operating labor$125,0001 FTE and 124,862 $/yearEstimated manpower level$125,000$0Cost Manual, pdf 48773Maintenance labor & materials$3,523,000(DC) X 3.0%$3,762,000$948,000TCI X 1.5%, Cost Manual, pdf487.74Yearly emissions testing$25,000Based on other projects withsimilar emissions testingscope$25,000$25,00075Catalyst activity testing$5,000Engineering estimate$5,000$5,00076Fly ash sampling and analysis$20,000Engineering estimate$20,000$20,00077Total fixed annual costs$3,698,000$3,937,000$998,0007879Variable annual costs282San Juan Unit 3 @ 0.05 lbs/MMBtu80Reagent$1,415,000543 lb/hr and 700 $/ton B&VCalculated$1,415,000$1,000,265Ammonia cost reduced to$475/ton. Ammonia flow rateincreased by 0.25/0.24.81Auxiliary and ID fan power$2,194,0004,881 kW and 0.06095 $/kWhB&V Calculated$2,194,000$607,594Adjusted to 0.3% gross capacityand $0.050/kWh82Catalyst replacement$538,00083 m3 and 6,500 $/m3 2 yrcatalyst replacement rate$538,000$238,375B&V assumed a catalyst volumesufficient to reduce NOx from 0.3to 0.044 lb/MMBtu, so adequatefor 0.05. Unit cost reduced to$6000/m3 and FWF = 0.48.83Total variable annual costs$4,147,000$4,147,000$1,846,2348485Total direct annual costs (DAC)$7,845,000$8,084,000$2,844,2348687Indirect Annual Costs88Cost for capital recovery$24,196,000(TCI) X 9.74% CRF at 7.41%interest & 20 year life$24,196,000$5,092,000(TCI) x 8.059% CRF at 7%interest & 30 year life89Total indirect annual costs (IDAC)$24,196,000$24,196,000$5,092,0009091Total Annual Cost (TAC) = (DAC) + (IDAC)$32,041,000$32,280,000$7,936,2349293Emission Reductions(ton/yr)4,931B&V BART Analysis, TableES-24,9315,360Increased tons NOx reduced by(0.25/0.23) for outlet of 0.05lbs/MMBtu9495Cost Effectiveness ($/ton)6,4986,5461,4819697Cost ($/kW)4574821169899100101102Interest Rate0.07103Lifetime30104CRF0.0806292San Juan Unit 4 @ 0.05 lbs/MMBtu3Capacity (MWg)5444Capacity (MWn)50756COST ANALYSIS B&VCOST ANALYSIS FOX78Cost Item7/11/2007Remarks/Cost BasisEscalationEscalationEscalationRevisions910/22/2010to Oct 2011to Oct 2011(percent)10/10/2010Adjusted to 2010 Dollars10($)(percent)($)($)1112CAPITAL COST13Direct Costs14Purchased equipment costs15Anhydrous Ammonia Injection System$559,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$605,9565.3$550,344Adjusted to use final contractaward and remove installation16Anhydrous Ammonia Vaporization System$559,000Scaled from B&V databasebased on ammonia flow, using0.6 scale factor8.4$605,9565.3$550,344Adjusted to use final contractaward and remove installation17Reactor Box, Breeching and Ductwork$5,083,200Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$5,652,5180.0$3,585,687Adjusted to use final contractaward and reduced by 10% toaccount for cheaper materials per10/21/10 Responses, p. 2.18Ductwork Expansion Joints$186,500Scaled from B&V databasebased on flue gas flow, using0.6 scale factor8.4$202,1665.3$166,853Adjusted to use one unit, removefreight, scaled using actual unitflow rates, and reduce cost by10% to account for lessexpensive materials ofconstruction.19Catalyst$3,245,000Catalyst volume determinedbased on unit size & Noxremoval, $6500/m3 of catalyst0$3,245,0000.0$0Annualized cost must be reportednet of replacement materials.Cost Manual, pdf 47, 486.20Sonic Horns$188,000Actual price from similarlysized unit, escalated to 2007dollars8.4$203,7925.3$149,526Final contract award21Elevator$1,236,000Actual price from similarlysized unit, escalated to 2007dollars8.4$1,339,8245.3$633,097Adjusted to use final contractreward and to remove installationfrom vendor quote22Structural Steel$6,252,000Scaled from B&V databasebased on flue gas flow, using0.6 scale factor11.2$6,952,2240.0$6,396,471Adjusted to use final contractaward and remove complexityfactor.23SCR Bypass$10,000,000Taken from another B&Vproject of similar size8.4$10,840,0005.3$0Not required for oil firing duringstartup24NOx Monitoring System$440,000Actual price from similarlysized unit, escalated to 2007dollars8.4$476,9605.3$269,901Adjusted to use final contractaward, to require 1 trainingsession for the station, and toremove maintenance contract302San Juan Unit 4 @ 0.05 lbs/MMBtu25Electrical System Upgrade$484,000Actual price from similarlysized unit, escalated to 2007dollars8.4$524,65611.2$538,20826Auxiliary Electrical Equipment Requirements$8,350,000Estimated in the B&V10/22/10 Cost Analysis0$8,350,0000.0$1,503,000Adjusted to 18% of B&V estimate27Instrumentation and Control System$291,000Actual price from similarlysized unit, escalated to 2007dollars8.4$315,4445.3$468,707Adjusted to use final contractaward and remove escalation.28Subtotal capital cost (CC)$36,873,700$39,314,496$14,812,13729Gross Receipt Tax$2,282,000(CC) X 6.2%$2,433,000$877,000Adjusted to remove elevatorcosts30Freight$1,844,000(CC)X 5.0%$1,966,000$345,000Adjusted to remove sonic horns,elevator, structural steel, N0xmonitoring system, I&C system.31Total purchased equipment cost (PEC)$41,000,000$43,713,496$16,034,1373233Direct installation costs34Foundation & supports$12,300,000(PEC) X 30.0%6.2$13,062,60035Handling & erection$12,300,000(PEC) X 30.0%6.2$13,062,60036Electrical$6,150,000(PEC) X 15.0%6.2$6,531,30037Piping$1,025,000(PEC) X 2.5%6.2$1,088,55038Insulation$4,100,000(PEC) X 10.0%6.2$4,354,20039Painting$410,000(PEC) X 1.0%6.2$435,42040Demolition$4,100,000(PEC) X10.0%6.2$4,354,20041Relocation$2,050,000(PEC) X5.0%6.2$2,177,10042Total direct installation costs (DIC)$42,435,000$45,065,9704.4$10,075,191(PEC) X 62%. Adjusted toremove instrumentation andcontrol system.4344Air preheater modifications$5,090,000Based on a budgetary quotereceived for the project8.4$5,517,5605.3$0Not required for SCR.45Balanced draft conversion$18,714,000Adjusted from a B&Vbalanced draft conversionproject based on differencesin scope8.4$20,285,9765.3$2,478,804Adjusted to 18% less fanmodifications B&V 10/22/10 CostAnalysis, Table 546Induced draft fans5.3$4,275,180FD & ID fans minus thepressurized furnace differential.B&V 10/22/10 Cost Analysis,Table 5.47Site preparation$2,000,000Contingency for siteunknowns, such asunderground utilities0$2,000,000$0Excessive contingencies perCost Manual, pdf 44, 486.48Buildings & enclosures$500,000Contingency for general sitebuilding requirements0$500,000$0Excessive contingencies perCost Manual, pdf 44, 486.49Total direct costs (DC) = (PEC) + (DIC)$109,739,000$117,083,000$32,863,31250312San Juan Unit 4 @ 0.05 lbs/MMBtu51Indirect Costs52Engineering$7,682,000(DC) X7.0%$8,195,810$3,286,000(DC) X 10%, Engineering &Home Office Fees, Cost Manual,pdf 486, Table 2.553Owner's cost$5,487,000(DC) X 5.0%$5,854,150$0Included in Engineering & HomeOffice Fees.54Construction management$10,974,000(DC) X 10.0%$11,708,300$055Construction indirect$26,445,000B&V labor market review6.2$28,084,5904.4$13,151,894Reduced to 60% total installationlabor56Start-up and spare parts$3,292,000(DC) X 3.0%$3,512,000$986,00057Performance test$200,000Based on other projects withsimilar emissions testingscope$200,000$200,00058Contingencies$21,948,000(DC)X 20.0%$23,416,600$1,643,000(DC) X 5%, Cost Manual, pdf486, Table 2.559Total indirect costs (IC)$76,028,000$80,972,000$19,266,8946061Interest During Construction (IDC)$20,648,000[(DC)+(IC)] X 7.41% 3 years(project time length X 1/2)$20,648,000$0Not permitted under Cost Manualapproach62Loss Generation during Outage (GEN)$23,674,0005 weeks and 0.06095 $/kWh12 weeks required for BDC,$23,674,000$0Not required637 weeks major outageavailable64Project Contingency$7,819,531(DC + IC) X 15%, Cost Manual,pdf 486, Table 2.5.6566Total Capital Investment67(TCI)=(DC)+(IC)+(IDC)+(GEN)$230,089,000$242,377,000$59,949,738Adjusted to include projectcontingency6869ANNUAL COST70Direct Annual Costs71Fixed annual costs72Operating labor$125,0001 FTE and 124,862 $/yearEstimated manpower level$125,000$0Cost Manual, pdf 48773Maintenance labor & materials$3,292,000(DC) X 3.0%$3,512,000$899,000TCI X 1.5%, Cost Manual, pdf487.74Yearly emissions testing$25,000Based on other projects withsimilar emissions testingscope$25,000$25,00075Catalyst activity testing$5,000Engineering estimate$5,000$5,00076Fly ash sampling and analysis$20,000Engineering estimate$20,000$20,00077Total fixed annual costs$3,467,000$3,687,000$949,0007879Variable annual costs322San Juan Unit 4 @ 0.05 lbs/MMBtu80Reagent$1,388,000533 lb/hr and 700 $/ton B&VCalculated$1,388,000$981,844Ammonia cost reduced to$475/ton. Ammonia flow rateincreased by 0.25/0.24.81Auxiliary and ID fan power$2,215,0004,881 kW and 0.06095 $/kWhB&V Calculated$2,215,000$607,594Adjusted to 0.3% gross capacityand $0.050/kWh82Catalyst replacement$541,00083 m3 and 6,500 $/m3 2 yrcatalyst replacement rate$541,000$239,705B&V assumed a catalyst volumesufficient to reduce NOx from 0.3to 0.044 lb/MMBtu, so adequatefor 0.05. Unit cost reduced to$6000/m3 and FWWF = 0.48.83Total variable annual costs$4,144,000$4,144,000$1,829,1438485Total direct annual costs (DAC)$7,611,000$7,831,000$2,778,1438687Indirect Annual Costs88Cost for capital recovery$22,411,000(TCI) X 9.74% CRF at 7.41%interest & 20 year life$22,411,000$4,831,000(TCI) x 8.059% CRF at 7%interest & 30 year life89Total indirect annual costs (IDAC)$22,411,000$22,411,000$4,831,0009091Total Annual Cost (TAC) = (DAC) + (IDAC)$30,022,000$30,242,000$7,609,1439293Emission Reductions(ton/yr)4,837B&V BART Analysis, TableES-24,8375,258Increased tons NOx reduced by(0.25/0.23) for outlet of 0.05lbs/MMBtu9495Cost Effectiveness ($/ton)6,2076,2521,4479697Cost ($/kW)4234461109899100101102Interest Rate0.07103Lifetime30104CRF0.0806