### March 2011 

# Revised BART CostEffectiveness Analysis for Tail-End Selective Catalytic Reduction 

# atthe Basin Electric Power Cooperative Leland Olds Station Unit 2 Final Report

Prepared for U.S. Environmental Protection Agency Region 8 Air Quality Planning Unit 1595 Wynkoop Street

Mail Code: 8P-AR Denver, CO 80202-1129
Prepared by Phyllis Fox, Ph.D., PE (Consultant)

RTI ProjectNumber 0209897.004.095

### TABLE OF CONTENTS

I. 

### INTRODUCTION AND SUMMARY II. COSTING METHOD III. REVISED COST EFFECTIVENESS ANALYSIS A. CAPITAL COST 

### 1. SCR Capital Cost 2. Sorbent Injection System 3. Advanced Separate Overfire Air (ASOFA) B. OPERATING AND MAINTENANCE COSTS 

### 1. Levelized O&M Costs 2. Catalyst Replacement Costs

a. Ash and Poisons b. Catalyst Lifetime c. Number ofCatalyst Layers d. Time Value ofMoney e. Unit Catalyst Cost f. 

### Catalyst Volume g. Catalyst Changeout Time 3. Cost ofUtilities And Supplies

a. Ammonia b. Natural Gas c. Power 4. Capacity Factor C. NOx

### EMISSION REDUCTION D. COST EFFECTIVENESS SUMMARY

2

### I. INTRODUCTION AND SUMMARY A costeffectiveness analysis evaluates the cost ofcontrolling pollution in dollars perton ofpollutantremoved. In response to a request from the North DakotaDepartment ofHealth (NDDH), Sargent & 

### Lundy prepared a cost effectiveness analysis to control nitrogen oxides (NOx) emissions from Basin Electric Power Cooperative's (BEPC's) Leland Olds Unit 2 using tail-end selective catalytic reduction. l 

### This analysis evaluated five options for tail-end SCRwith reported costsranging from $4,170/ton

### to $5,976/ton. 2 

### NorthDakota, in tum, used Sargent & 

### Lundy's analysis to make a BestAvailable Retrofit (BART) determination for Leland Olds Unit 2. North Dakota concludedthattail-end SCRis technically feasible but eliminated it because the cost effectiveness and incremental cost ofSCRwere excessive. 3

, 

### Ireviewed the Sargent & 

### Lundy cost effectiveness analysis and supporting draft Excel spreadsheets4 

### andprepared arevised costeffectiveness analysis for both SCR alone and SCRplus advanced separated overfire air (ASOFA), correcting errors I found. I evaluated SCR

### +ASOFA combined because this is the primary option thatthe Sargent & 

### Lundy analysis considered. The ASOFA was installed in November 2009. Thus, I also separately determined the cost effectiveness ofSCR alone. My review was hampered by the lack ofsupport for many ofthe assumptions inthe Sargent & 

### Lundy analysis. I estimate the cost effectiveness ofa tail end SCRplus ASOFA at Leland Olds Unit 2 to be about $1,954/ton 

### and ofSCR alone, after ASOFA is installed, to be $2,609/ton. 

### My revised cost analysis is compared to Sargent & 

### Lundy's in Exhibit 1. 

### II. COSTING METHOD Costeffectiveness, measured in dollars per ton ofpollutant removed, is calculated according to the EPA Air Pollution Control CostManual or "Cost Manual",s as stipulated in the BART Guidelines. While use ofthe BART guidelines is required for powerplants

lLetter from Cris Miller, Senior Environmental Project Administrator, Basin Electric PowerCooperative, to Terry L. O'Clair, North Dakota Department ofHealth, Attaching Letter from William DePriest, Senior Vice President, Environmental Services, to Cris Miller, Re: BART Evaluation Update

- Tail End SCR, May 27, 2009 (5/27/09 S&L Cost Analysis).

2 5/27/09 S&L Cost Analysis, Table 2.5-5.

3 North Dakota Department ofHealth (NDDH), BART Determination for Leland Olds Station Units I and 2, undated.

4 Email fromGailFallon.EPARegion8.toPhylJisFox.Re: Sargent & Lundy Spreadsheets for Leland Olds, February 8, 20 10. The attached spreadsheets are referred to in this report as the "Sargent& Lundy Excel Spreadsheets." There are three, captioned as follows: (I) low-high dust scr-Ieland 0lds2

- Sens2-cat Iife_052109.xls; (2) low-high dust scr-Ieland 0lds2

- Sens2-cat life.xls; (3) low-high dust scr-Ieland 0lds2

­ Sens2-cat life_05209.xls. These were produced in responseto an EPA Section 114 request.
5 U.S. EPA, EPA Air Pollution Control Cost Manual, Report EPA/452/B-02-001, 6th Ed., January 2002 ("CostManual"), The EPA Air Pollution Control Cost Manual is the currentname for what was previously known as the OAQPS Control Cost Manual, the name for the Cost Manual in previous (pre-2002) editions ofthe Cost Manual.

3

### with a capacity greaterthan 750 MW, the EPA encourages States to use the guidelines for all BARTdeterminations to assure uniformity in making cost effectiveness determinations. 6 

### A control technology is consideredto be "costeffective" ifit falls within a reasonable range ofcost-effectiveness estimates. The Cost Manual sets outboth a general costing procedure and specific methods for individual pollutioncontrol methods. Sargent & Lundy failed to follow the general costing procedure which has been used for decades for regulatory costeffectiveness analyses. Costeffectiveness 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 ofpollutantremoved. Cost effectiveness is determined by comparing annual costperton ofpollutant removed for the source ofinterestto the range ofcosteffectiveness values for other similarpermit decisions. Ifa given cost effectiveness value falls withinthe range ofcosts borne by others, itis per se cost effective unless unusual circumstances exist atthe source.7 

### Thus, cost effectiveness is a relative determination, based on costs borne by other similar facilities. To compare costs among units, a level playing field must be established by following the same costrules in each determination. 8 

### The Sargent & Lundy cost estimating method deviates from the standard procedure developed by EPA to establishthe range ofacceptable cost effectiveness values. Thus, comparisonofSargent & Lundy's cost effectiveness values withthose estimated by others who did follow the Manual is meaningless.
In evaluating costeffectiveness, it is importantthat a consistent setofrules be used. These rules are set outin guidelines promulgated by EPA for determining BART9 

### inAppendix Y to Part 51, "Guidelines for BART Determinations Underthe Regional Haze Rule." These Guidelines include methods to determine both cost and cost effectiveness. For cost analyses, the Guidelines stipulate: "In order to maintain and improve consistency, cost estimates should be based onthe OAQPS Cost Control Manual, where possible."lo While some SCR-specific designparameters and estimating methods inthe CostManual may notbe applicable to tail-end SCR, the costmethodology and accounting practices should be followed using site specific information where available.
670 FR 39108 (July 6, 2005).

7 70 FR 39168 (July 6, 2005).

8 See discussion ofthis issue in: Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry O'Clair, Director, Division ofAir Quality, North Dakota Department ofHealth, Re: EPA's Comments on the North Dakota Department ofHealth's April 2010 Draft BACT Detennination for NOx for the Milton R. Young Station, May 10,2010,pp. 14-16: ("The standard approach is outlined in the Control Cost Manual, so that comparisons ofcost-effectiveness can be made with other projects nationally.").

9 See, e.g., 70 FR 39158 (July 6, 2005) ("States must follow the guidelines in making BART detenninations on a source-by-source basis for 750 megawatt (MW) powerplants

...").

10 70 FR 39166 (July 6, 2005).

4Thepurpose ofthe BART Guidelines is to prepare a regulatory cost estimate that allows comparison across multiple units. This estimate is expressed in real orconstant dollars, less inflation. Consistency among analyses performed across the United States is essential to establish cost effectiveness. Sargent & Lundy violatedthese guidelines by including projects that are notrequired for a retrofit SCR atLeland Olds (sorbent injection system); extrapolating capital costs from inflated unit capital cost; by using levelized O&M costs; and by using excessively high unit costfor utilities and commodities, among others.
These deviations from standardpractice make it appearthatthe costto control NOx using tail-end SCR atLeland Olds is higherthan at other similar sources. However, these inflated costs are due to the costingmethod, notto any unique circumstances at Leland Olds Unit2 that make SCRunusually costly. While a tail-end SCRcanresultin highercoststhan a conventional high-dust installation, those costs are explicitly accounted for inthe analysis that follows. 

### III. 

### REVISED COST EFFECTIVENESSANALYSIS
The following sections identify some ofthe sources ofoverestimation in the cost analysis in the May 27, 2009 Sargent & Lundy CostAnalysis. I I This analysis estimated the cost effectiveness in dollars perton ($/ton) for five separate tail-end SCRcases. These alternatives varied capital cost, catalyst life, natural gas cost, and ammoniacost (Alternatives E-I) for SCRplus ASOFA. Myrevised cost analysis is presented inExhibit 1. My analysismodifies draft Excel spreadsheetsprovidedby Sargent & Lundy in response to EPA's Section 114 request. My analysis is found inExhibit 1a, ColumnE, Fox Revised Costfor SCR

### + ASOFA. The Sargent & Lundy cost options are found in Exhibit 1, Columns F - J, labeled Cases I through E. I also prepared a cost analysis for SCR alone, as ASOFA is already installed, which is the current situation.
The 

### 5/27/09 Sargent& Lundy Cost Analysis provided to NDDH reports only lump sumcapital and operating costs without any supporting calculations. Itis not possible to determine howthe cost effectiveness values were derived from the information in this letterreport.
In January 2011, Sargent & Lundyprovided Excel spreadsheets inresponse to an EPA Section 114 request.12 These spreadsheets disclose the formulas and calculations usedto generate the cost informationinthe 

### 5/27/09 Sargent & Lundy CostAnalysis. was able to rearrange andmodify these spreadsheets to yield costeffectiveness values

115/27/09 S&L Cost Analysis, Tables 2.5-1 to 2.5-5.

12 Letter from Stephen S. Tuber, Assistant Regional Administrator, EPA Region 8, to William DePriest, Senior Vice President, Environmental Services, Sargent & Lundy LLC Re: Request for Information for Basin Electric's Leland Olds Station in North DakotaPursuantto Section 114 ofthe Clean Air Act, December 6, 2010, p.l: (Provide all calculations, formulas, and methodologies, including electronic spreadsheet files, used to generate the costs presented in the Sargent & Lundy LLC letter to Basin Electric Power Cooperative dated May 27,2009 on the subject of"BARTEvaluation Update

- Tail End SCR.").

5 Ithat agree with those inthe 5/27/09 Cost Analysis sent to NDDH, rounded to two significant figures. This spreadsheet is Exhibit 1. I was unable to matchthe 5/27/09 analysis exactly (comparerows 80 and 81) due to differences in rounding methods

.. These spreadsheets are the basis for muchofmy discussion below as they contain underlying calculations that are missing from the 5/27/09 Sargent & Lundy Cost Analysis. However, evenwiththe spreadsheets, many assumptions remainunsupported. 

### A. CAPITAL COST 

### In the selective catalytic reductionprocess or SCR, the gas stream ispassed through a catalystbedin the presence ofammoniato reduce NOx to nitrogen gas and water. The process is termed "selective" because the ammoniapreferentiallyreacts with NOxrather than other components inthe flue gas. A catalyst is usedto enhance the reaction betweenNOx and ammonia. The SCRcan be located in three places inthe gas stream: 

### (l) high dust, hot-side at the outlet ofthe boiler where dust loadings are high; (2) low dust afterthe particulate control device where dust loadings are low; and (3) tail end, at the tail end ofthe plant, betweenthe S02 scrubber and the stack. 13 This analysis assumes the tail-end location (Fig. 1), based on Sargent & Lundy'scost analysis. This location is preferable in this case as it minimizes the amount ofash and catalystpoisons that would otherwise be present inthe flue gases, thus increasing catalyst life and decreasing operating costS.1 4

13 McIlvaine, Next Generation SCRChoices

- High-Dust, Low-Dust and Tail-End, FGD & DeNOx Newsletter, no. 369, January 2009.

14 See, e.g., Gerd Beckman and Clayton A. Erickson, Operating Experience and Future Challenges with SCR Installations, p. 4 ("Themain advantage ofthis arrangement [tail end] is the considerably smaller loss ofactivity overthe working life compared to the high dust catalysts, because many catalytic poisons such as arsenic, alkali metals, and alkaline earth metals are removed in the upstream flue gas cleaning stages."), Power-Gen Intemational2000, November 14,2000, Available at: http://www.babcockpower.com/pdf/rst170.pdf

6

### Figure 1. Tail-End SCR Arrangement (EPA/452/B-02/00l)

tJ,0ILER i



### The SCR consists ofa metal frame placed in the flue gas path that is stuffed with hundreds ofmodules orblocks ofcatalyst, each with many openings to allow the gas to pass through. The size ofthe openings is called the pitch. The catalyst consists ofan inert substrate impregnated with "active" elements such as vanadium, tungsten, and molybdenum. The ammonia is injected into the flue gas ahead ofthe SCRto accelerate the reaction. A small amount ofthe ammoniadoes not react with NOx 

### and slips through the catalyst. This ammonia is known as "ammonia slip."
Installed capital cost was estimated by Sargent & 

### Lundy from the sum ofseveral components: the cost ofthe SCR combined with advanced separated overfire air (ASOFA), and in some scenarios, an additional cost for a sorbent injection system. These costs were rolled into a single unit capital cost expressed in dollars perkilowatt of capacity. The SCRcost is overstated, the sorbent injection system is not required, and the ASOFA is already installed. 

### A.I SCR Capital Cost The 5/27/09 Sargent & 

### Lundy Cost Analysis reports a capital costrange of$165.8 to $170.8 million for installed capital costs ofSCR

### +ASOFA in 2009 dollars.IS 

### These costs were estimated from a lump sum unit capital cost estimate expressed in dollars per kilowatt ofelectricity generated. These costs are overestimatedbased oncosts reported for other similar installations. However, I am not able to determine why as Sargent & 

### Lundy did not supporttheirunit capital costestimate. Equipment (e.g., reactor housing, ducts, bypass, ammonia injection system, sonichorns, etc) and installation costs which are commonlybrokenout and separately costed are not identified. The following sections discuss costs for other similar retrofits and discuss one component ofthose costs, sorbent injection, that should not have been included.

15 5/27/09 S&L CostAnalysis, Table 2.5-2.



### 7

### The capital cost ofthe SCRin combination with advanced separated overfire air (ASOFA) and sorbent injection (SI) in the 5/27/09 

### Sargent & 

### Lundy Cost Analysis was estimated by multiplying the generating capacity of440 MWby a unit capital cost factor that ranges from $376/kW

### to $387/kW

### in 2009 dollars.!6 These costs include the cost of a sorbent injection system (387-376=$11IkW) and ASOFA ($26IkW)Y 

### The SCRtaken alone is $3501kW in 2009 dollars 18 

### or $373/kW

### in 2010 dollars.!9 This section compares the SCRunit capital cost in 2010 dollars with the cost ofother SCRretrofits. As demonstrated below, a unit cost of$373/k

### W for SCRalone is high for the subject application. Five industry studies conducted between 2002 and 2007 have reported the installed unit capital cost ofSCRs, orthe costs actually incurred by owners, to range from $79/kW

### to $3161kW in 2010 dollars. These studies and other SCRcost data are reviewed below. Costs are escalated to 2010 dollars using the Chemical Engineering Plant Cost Index ("CEPCI") as reported in Chemical Engineering. These studies show actual capital costs are lowerthan estimated by Sargent & 

### Lundy for Leland Olds ($373/kW) 

### for SCR alone. The first study evaluatedthe installed costs ofmore than 20 SCRretrofits from 1999 to 2001. The installed capital costranged from $112 to 

### $250/kW, convertedto 2010 dollars?O The second survey of40 installations at 24 stations reported a costrange of$80 to 

### $256/kW, converted to 2010 dollars?! Thethird study, bythe Electric Utility Cost Group, surveyed 72 units totaling 41 GW, or 39% ofinstalled SCR systems in the U.S. This study reported a costrange of$

### 125/kWto 

### $277lkW, converted to 2010 dollars.22 

### A fourth study, presented in a course atPowerGen 2005, reported an upper

16 The 5/27/09 S&L Cost Analysis states on p. 9 that capital costs were calculated from $387/kW. However, $170,800/440 MW = $388/kW was actually used. This factor includes the SCR, ASOFA, and a sorbent injection system. 175/27/09 S&L Cost Analysis, Table 2.5-1 and Sargent & Lundy Excel Spreadsheet (which used $350/kW).

L8 5/27/09 S&L Cost Analysis, p. 4 (2009 dollars).

19 The cost of just SCR, escalated to 2010 dollars, based on the most recent CEPCI for October2010 (Chemical Engineering. January 20II, p.60) is: (556.2/521.9)(350) = $373/kW.

20 Bill Hoskins, Uniqueness ofSCRRetrofits Translates into Broad Cost Variations, Power Engineering, May 2003. Available here: http://www.powergenworldwide.com/index/display/articledisplay/I76832/articles/powerengineering/volume-I07/issue-5/features/uniqueness-of-scr-retrofits-translates-into-broad-cost­ variations.html. The reported range of $80 to $160/kW was converted to 2010 dollars ($112

- $250/kW) using the ratio ofCEPCI in October2011 to 2002: 556.2/395.6.
211. Edward Cichanowicz, Why are SCRCosts 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 ($80

- $256/kW) using the ratio ofCEPCI for October2010 to 1999 (556.2/390.6) for lower end ofthe range and 2010 to 2003 (556.7/401.7) for upper end ofrange, based on Figure 3.
22 M. Marano, Estimating SCRInstallation Costs, Power, JanuarylFebruary 2006. The reported range of $100

- $221/kW was converted to 20I0 dollars ($125

- $277/kW) using the ratio ofCEPCI for October


### 8

### bound range of$190/kW

### to $214/kW, 

### converted to 2010 

### dollars.23 

### A fifth summary study reports recent applications that were installed in 2006 

### and 2009. 

### The costs for these units, convertedto 2010 

### dollars, ranges from 

### $195/kW to 

### $330/kW.24 Thus, the overall range for these industry studies is $80/kW

### to 

### $330/kW in 2010 

### dollars. The upper end ofthis range is for highly complexretrofits with severe space constraints, such as Cinergy's GibsonUnits 

### 2 - 4. Gibson, a highly complex, spaceconstrained retrofit inwhichthe SCRwas built 230 

### feet above the power stationusing the largest crane inthe world,25 only cost 

### $252/kW in 2010 

### dollars.26 

### The Leland aIds site is not similarly constrained. Otherrecent estimates not included in these surveys confirm thatthe Leland aIds SCRcapital costs are overestimated. The unit capital cost for the St. Johns River Power Park (SJRPP) SCRthat burns a very challenging blend ofcoke/coal is $188/kW

### in 2010 

### dollars.27 

### Wisconsin Electric estimatedthe costto retrofit SCR on Oak Creek Units 

### 5-8 to be $187/kW 28 

### for a cold-side SCR. This cost was certified in July 2008 

### for constructionbythe Wisconsin Public Services Comrnission.29 

### The comparable cost for a tail-end SCRis $175/kW. 

### Wisconsin Power and Light estimated the costto retrofit SCR

20I0 to 2004: 556.2/444,2. Available here: http://findarticles.com/p/articles/mi_qa5392/is_200602/ai

_n21409717/print?tag=artBody;coll.

23 PowerGen 2005, Selective Catalytic Reduction: From Planningto 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 ($190

- $214/kW) using the ratio ofCEPCI for October 2010 to 2005 (556.2/468.2).

241. Edward Cichanowicz, Current Capital Cost and Cost-Effectiveness ofPower 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 20I0 dollars ($195

- $250/kW) using the ratio ofCEPCI for October 2010 to 2006 (556.2/499.6). The 2009 value of$300/kWwas converted to October 2010 dollars ($330/kW) using the ratio ofCEPCI for July 2010 to 2009 (556.2/521.9).

25 Bob Ellis, Standing on the Shoulder ofGiants, Modem Power Systems, July 2002.

26 McIlvaine, NOx MarketUpdate, August 2004. SCRwas retrofit on Gibson Units 2-4 in 2002 and 2003 at $179/kW. Assuming 2002 dollars, this escalates to ($179/kW)(556.2/395.6) = $252/kW. http://www.mcilvainecompany.com/sampleupdateslNoxMarketUpdateSample.htm.

27 Email from Norem to Kordzi, October 21, 20I0, PNM Responses to Follow-Up Questions from October 14,2010 Conference Call Regarding BART Cost Estimate, Response to Question 7: (556.2/499.6)($228,092,914)(12(675MW)(1000)) =$188/kW.

28 Wisconsin Electric Power Company's Application to Install Wet Flue Gas Desulfurization and Selective Catalytic Reduction Facilities and Associated Equipment on Oak Creek Power Plant Units 5, 6, 7 & 8 for Control ofSulfur Dioxide and Nitrogen Oxide Emissions, Appendix C, Emission Reduction Study, Volume I, Addendum August 20,2007. Unit costfor cold -side unit = ($190,500,000/1,135,000 kW)(556.2/499.6)
= $187 kW. Unit cost for tail-end unit = ($178,600,000/1,135,000 kW)(556.2/499.6) = $175/kW.

29 Certificate and Order, Application to Install Wet Flue Gas Desulfurization and Selective Catalytic Reduction Facilities and Associated Equipment on Oak Creek Power Plant Units 5, 6, 7 & 8 for Control of Sulfur Dioxide and Nitrogen Oxide Emissions, Case 6630-CE-299, July 10,2008. Available here: http://www.we-energies.com/home/OCPP

_approvalPSCWOrder.pdf.

9

### on the 430-MWEdgewater Unit 5to be $324/kW in January 2008,30 which escalates to 

### $343/kW in 2010 dollars?! Similarly, AmericanElectric Power (AEP) estimatedthatthe average capital cost to install SCRs to remove 85%-93% ofthe NOx 

### from many ofits units was 

### $162/kW.32
This dataindicates that Sargent & 

### Lundy's estimates ofcapital costto retrofit SCRat Leland Olds 

### ($373/kW in 2010 dollars) is higher than actual installed cost for existing retrofit SCRs, includingthose with extreme retrofit difficulty and those requiring flue gas reheat. Thus, the resulting cost effectiveness is conservative in favor ofBEPC. It

### is notpossible to further comment on why it is excessively high as this unit cost is not supported inthe record. Thus, my cost effectiveness values reported below are upper bounds, i.e., cost effectiveness is more favorable thanmy estimates suggest. While there are issues that may elevate operating costs ofan SCRat Leland Olds comparedto some sites, the issues are not more costly than many existing complex retrofits at space constrained site using difficultfuels such as coke and PRB coal. Further, the SCRequipmentat Leland Olds is conventional, i.e., reactorhousing, ammonia injection system, ductwork modifications. Thus, the capital coststo retrofit SCRon a lignite-fired boiler should be well within the range ofcapital costs for other retrofits. As discussed below, catalyst volume and lifetime are key cost drivers, which, whenproperly calculated, will reduce both capital and operating costs. 

### A.2 Sorbent Injection 

### System Sargent & 

### Lundy claimsthat an SCRon Leland OldsmighttriggerNew Source Reviewpermitting for sulfuric acid mist, requiring sorbent injection. They evaluated sorbent inJection in their alternatives H and I and assumed it would cost $5,000,000 or $11/kW.3 Their sulfuric acid mist calculations, which are unsupported, assume that 1% ofthe sulfur dioxide (S02) exiting the wet scrubberwould be converted to sulfuric acid mist (SAM) in a tail-end SCR,34
An SCRcatalyst does convert some ofthe S02 in flue gases to sulfurtrioxide (S03). The sulfur trioxide combines with water inthe exhaust gases and is converted into very small liquid droplets ofsulfuric acid (H

### 2 S04 ), called sulfuric acid mist or SAM,

30 Wisconsin Power & Light Co., Certificate ofAuthority Application, Edgewater Generating Station Unit 5NOx 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. 31 Edgewater SCRcosts escalation to 2010 dollars: ($324!kW)(556.2/525.4) = $343/kW. 32 AEP, 2008 Fact Book, 43rd Financial Conference, Phoenix, AZ, pdf 103. Availablehere: http://www.aep.com/investors/present/documents/2008EEI-Fact-Book.pdf.

33 This is estimated by subtracting the capital cost ofCases E, F, and G (with no sorbent injection) from cases Hand 1(with sorbent injection). This cost is included in the unit capital cost, i.e., $387!kWfor cases H and I and $376!kWfor cases E, F, and G or ($387!kW

- $376!kW)440,000 kW = $4,840,000. 345/27/09 S&L CostAnalysis, p. 6.



### 10

### before it leaves the stack.35 The extent ofthis oxidation depends onthe catalyst formulation and the SCR operating temperature.36 Low conversion catalysts capable of achieving an S02to S03 conversion as low as 0.1% per layer ofcatalyst in the high dust, hot (>650 F) position are available.3 ? 

### Tail-end SCRs operate at much lower temperatures, 525 F to 600 F, thanhigh dust SCRs, which significantly reduces the conversion ofS02to S03.38 The S02to S03 conversionrate is an SCRdesign parameter that is typically specified to assure sulfuric acid mist emissions remain low. Thus, ifsulfuric acid mist were a concern, a low conversion catalystcould be specified. For example, the design basis could specify atotal S02to S03conversion of0.2% with three layers installed. Therefore, even assuming Sargent & Lundy's calculations, the sulfuric acid mist emissions would drop from 24.1 tonlyr based on 1% conversion to 4.8 tonlyr based on 0.2% per layer. This is well belowthe significance threshold of7 tonlyr. Thus, Ihave not included any costs for a sorbent injection system inmy revised costanalysis. (Ex. 1, Cells E51, E74) 

### A.3 Advanced Separated OverfireAir (ASOFA) The Sargent & Lundy cost analyses include the cost ofASOFA in each ofits five 39 cases. The ASOFA was installed inNovember 2009. Thus, I 

### also determine the cost effectiveness ofSCRby itself. These calculations are included in Exhibit 1b.

35 R.K. Srivastava and others, Emissions ofSulfur Trioxide from Coal-Fired Power Plants, J. Air & Waste Manage. Assoc., June 2004, v. 54, pp. 750-762, p. 750; EPRl, Estimating Total Sulfuric Acid Emissions from Stationary Power Plants, Version 2010a, Technical Update, April 2010, p. 3-3; 1.1. Gmitro and T. Vermeulen, Vapor-Liquid Equilibria for Aqueous Sulfuric Acid, Am. Inst. Ch. Eng. Journal, v. 10, no. 5, Sept. 1964, pp. 740-76.

36 H. Gutberlet and others, S02 Conversion Rate ofDENOX Catalysts, VGB Kraftwerkstechnik, v. 70, no. 11, 1990, pp. 826

- 834; R.K. Srivastava and others, Emissions ofSulfur Trioxide from Coal-Fired Power Plants, J. Air & Waste Manage. Assoc., v. 54, June 2004, pp. 750-762.

37 DNxTM

_ Topsoe SCR DeNOx Catalysts Oxidation ofS02into S03 ("Topsoe has demonstrated superior performance together with low S02 oxidation under industrial conditions and has provided guarantees for S02 oxidation down to 0.1%."); Isato Morita and others, Development and Operating Results ofLow S02to S03 Conversion Rate Catalyst for DeNOx Application; HaldorTopsoe, DNXTopsoe SCR DeNOx Catalysts Oxidation ofS02 into S03, Accessed 1/1/11 at http://www.topsoe.comlbusiness areaslflue and waste**gas/~/media/PDF%20files/Scr** denox/Topsoe scr oxidation.ashx; Anthony C. Favale and others, Application and OperatingResults ofLow S02 to S03 Conversion Rate Catalyst for DeNOx Application at AEP Gavin Unit 1, Proceedings ofthe 2006 Environmental Controls Conference, U.S. Department ofEnergy, National Energy Technology Laboratory.

38 Selective Catalytic Reduction (SCR) Technical Feasibility for M.R. Young Station, Appendix D, Vendor Emails on North Dakota Lignite, Email from Flemming Hansen, HaldorTopsoe, to Hans Hartenstein, Evonik, Re: Tail-end SCR, June 24, 2008 ("Atthe low operating temperature expected at the tail-end position the S02 oxidation will be negligible.").

39 5/27/09 S&L Cost Analysis, pp. 6-7.



### 11

### B. OPERATING AND MAINTENANCE (O&M) COSTS Sargent& Lundy prepared a "hypothetical" cost estimate that evaluated a range for several operational costs, including the costofcatalystreplacement, ammonia, and natural gas. The upper ends ofthese ranges are major drivers in overestimating the cost effectiveness ofSCR at Leland Olds. 

### B.1 Levelized O&MCosts
In its 5/27/09 CostAnalysis, Sargent & Lundy estimatedthe annual O&M cost as the sum ofcertain fixed and variable expenses discussedbelow. The annual total was then levelized using methods laid outinthe original BEPC BART Determination Study. This methodtakes into accountthe inflation rate, the discount rate, and the equipment life. The sum offixed and variable O&M costs was levelized by multiplying it bythe O&M cost factor of 1.19314.40 

### In other words, O&M costs were increased by 20% to account for inflation and other future events.41


### The Cost Manual approach, recommendedbythe BART Guidance to estimate cost effectiveness, explicitlyexcludes future escalation as cost comparisons are made on a currentreal dollar basis. Inflation is not included in cost effectiveness analyses as they rely on the most accurate information available at currentprices and do not try to extrapolate those prices into the future. 42 

### I did not levelize O&M costs. (Ex. 1, Cell E45). 

### B.2 CatalystReplacement Costs The catalyst in an SCRis deactivated overtime by chemicals present in the flue gas stream thatblockthe catalystpores and poisonthe active sites. Thus, the catalyst must be replaced periodically. The annual costto replace catalyst is estimated from the number ofcatalyst layers, the total catalystvolume required to achieve the desired NOx 

### reduction, the costperunit volume ofcatalyst, the catalyst lifetime, and a future worth factor, as explained inthe EPA Cost Manual and set outinequations 2.50 to 2.53 therein. Sargent & Lundy selected values for each ofthese variables that significantly overstate catalystreplacement cost. They used arbitrary and unsupported values for all of the variables required to calculate catalystreplacement cost: (l) 

### a very shortcatalyst lifetime, 6 months to 1year; (2) frequent catalyst changeouts, every six months to one year; (3) very large catalyst volume, 530 m3; (4) 2 to 4 weeks to replace the catalyst; (5) a special outage for catalystreplacement, in whichthe unit is taken offlinejustto replace catalyst; (6) 

### high unit catalystcost, $7,500/m3; and (7) ignored the time value ofmoney.43

40 5/27/09 S&L Cost Analysis, Table 2.5-3, note (3).

41 Bums & McDonnell, BART Determination Study for Leland OIds Station Unit I and 2, Basin Electric Power Cooperative, Final Draft, August 2006, Section 1.3.5.

42 See, e.g., Cost Manual, p. 2-36, pdf50.

43 Sargent & Lundy Excel Spreadsheets and 5/27/09 S&L Cost Analysis, p. 7.



### 12

### These assumptions result in excessive annual cost to replace catalyst, amounting to $4 to $8 million for the catalyst itself(Ex. 1, Row 70) and an additional $7 to $15 million in lost generation (Ex. 1, Row 71). These factors also inflate capital cost, e.g., catalyst volume, and in part account for the overestimate ofcapital costs discussed above in Section A.l. The specific assumptions used to estimate catalystreplacement costs are not disclosed in the 5/27/09 S&L Cost Analysis. Rather, they are summed along with ammonia, natural gas and power and reported as total annual O&M cost. Thus, the underlying calculations and assumptions for each component cannotbe ascertained without additional information. I figured out some ofthe underlying calculations and assumptions using the Excel spreadsheets provided by Sargent & Lundy in response to EPA's Section 114 request. The assumptions used in these spreadsheets are inconsistent with standard SCR designprocedures and significantly overestimate catalyst replacement cost. Inthe following sections, I first explainwhy the studies and other information relied on by Sargent & Lundy do not supporttheir assumption that large volumes of catalyst mustbe replaced once to twice a year due to deactivation. Next, Iexplainwhy the specific variables they used overestimate catalyst replacement cost. Finally, I recalculate replacement cost in Exhibit 1by making the following changes to Sargent & Lundy's assumptions: (1) increasing catalyst lifetime from 4,400 hours to 24,000 operating hours; (2) changing the initial catalyst layoutto two active layers and one spare; (3) reducing the catalystvolume from 530 m3 

### to 440 m3; 

### (4) using a future worth factor of0.31; (5) reducingthe time to replace catalyst from 2 to 4 weeks to 3.6 days; and (6) eliminating catalystreplacement outages. The results ofthese changes reduce catalyst replacement cost from $11 to $23 million (catalyst 

### +power) estimated by Sargent & Lundyto $342,000 (Ex. 1, Row 70).

a. Ash and Poisons Sargent & Lundyprovided no specific support for its unusual catalyst replacement assumptions, citing "ourengineeringjudgment" and abriefunreferenced overview ofalleged ash plugging and alkaline (Na, K, Ca) poisoning due to the composition ofNorth Dakotalignites.44 

### Some slip stream studies were produced in response to EPA's Section 114 request.45 

### Sargent & Lundy apparently interprets these studies as demonstrating thatflue gases from North Dakota lignite fired cyclone boilers

44 5/27/09 S&L Cost Analysis, pp. 2-5.

45 See, e.g., Steven A. Benson, Ash Impacts on SCRCatalyst Perfonnance, Slides, February 21, 2006, BEPC_002065; S.A. Benson and others, Ash and Mercury Behavior in SCR Catalysts when Firing Subbituminous and Lignite Coals, Submittedto Fuel Processing Technology, BEPC_003820; S.A. Benson and 1.H. Pavlish, SCRCatalyst Perfonnance in Flue Gases Derived from Subbituminous and Lignite Coals, Fuel Processing Technology, v. 86, no. 5, February 25,2005, pp. 577-613, BPEC_003785; Y. Zheng and others, Deactivation ofV205-W03-Ti02 SCR Catalyst at Biomass Fired Power Plants: Elucidation of Mechanisms by Lab- and Pilot-Scale Experiments, Applied Catalysis B: Environmental, v. 83,2008, pp. 186-194, etc.

13have unique properties that deactivate SCRcatalyst much more rapidlythan flue gases from other fuels. However, these arguments are refuted byvendors and are not persuasive. First, these arguments are based mostly ondatacollected atboilerexits, in the high dust SCRposition, which is not proposed for Leland Olds. The SCRat Leland Olds wouldbe located atthe tail end, afterthe electrostatic precipitatorand newwet scrubber. These control devices remove the majority ofthe ash and catalystpoisons, allowing a longercatalyst lifetime than suggested inthe cited slipstreamtests.46 Flue gas composition data collected at Milton R. Young, which has an inefficient old wet scrubber, proves thatthe amount ofsubmicron alkali aerosols is so small thatcatalyst deactivation does not occurrapidly.47 Further, any remaining soluble alkaline substances do not poison the catalyst at tail-end SCRoperating temperatures. Significant deactivation only occurs ifcondensed moisture is present at the catalyst surface, i.e., when the catalyst is being cooled down to belowthe water dewpoint. This does not happen very often at a base-loadedunit such as Leland Olds and can be prevented by bypassing orbuttoning up the SCRreactor during forced outages ofa few days.48 Regardless, catalyst vendors have ample experience preventing moisture condensation in SCRcatalysts.49

46 See. e.g., 5/30/07 (Alstom) Letter in 5/8/08 Milton R. Young Additional Infonnation, p. 2 (As to high dust SCR, a worst case: "Based on our experience with wood fired units, a hot side ESP is effective in removingthe fly ash compounds that result in catalyst poisoning

...the fly ash constituents that can poison the catalyst will have been removed from the flue gas stream by the existing ESPs

.."), In Additional Infonnation and Discussion ofVendor Responses on SCRTechnical Feasibility North Dakota'sNOx BACT Determination for Milton R. Young Station Units I & 2, May 8, 2008 (5/8/08 Milton R. Young Additional Infonnation).

47 1/8/10 EPA Comments, Enclosure 2, pp. 24-25 ("As discussed extensively in the Minnkota BACT comments, the actual flue gas composition analysis data measured downstream ofthe wet FGD at MRYS proves that the amount ofsubmicron alkali aerosols is so small that catalyst deactivation does not occur rapidly and a relatively long catalyst life can reasonably expected (sic) compared to most HDSCR [high dust SCR] installations.");

48 5/6/08 Cochran (CERAM) Email, p. 2 (As to high dust SCR:, a worst case: "Dueto the high sodium and iron concentrations itis recommended that a full SCR bypass system be installed. During lay-up periods the catalyst would need to remain warm and dry (above condensing conditions), for instance with an air drying or dehumidification system. This may necessitate the use ofa dehumidifier and air lock system to access the reactor."), in 5/8/08 Milton R. Young Additionallnfonnation.

49 Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Additional Information and Discussion ofVendor Responses on SCRTechnical Feasibility, North Dakota's NOx BACT Detennination for Milton R. Young Station Units I & 2, Appendix A, VendorEmails, Email from John Cochran, CERAM Environmental, Inc., to Robert Blakley, Re: Request for Lignite SCRFeasibility Commercial and Technical Infonnation, May 6, 2008 ("Sodium is a catalyst poison. Concerns reported by Dr. Benson regarding high sodium content and fine fume are duly noted, but inadequate evidence is presented that this could be a fatal flaw to application ofSCR consideringthe flawed pitch and resultant pluggage ofthe catalyst used during the Coyote Station testing [North Dakota lignite]. Sodium is not a poison to catalyst at SCR operating temperatures. Significant deactivation can occur ifcondensed moisture transports sodium residing atthe surface into the catalyst pore structure during outage orlayup. CERAM has experience with high sodium applications to substantiate this effect. Important to avoid deactivation from sodium is the need to protect the catalyst from goingthrough a condensation event.")

14

### Second, mini tests relied on to desi§n the Leland Olds SCR do not always accurately predict full-scale performance. 5 

### Slipstream1 

### reactors are susceptible to ash accumulation due to wall effects.51 

### Turbulence at the inlet ofa slipstream catalyst is higher, which exaggerates deactivation rates comparedto a full-scale SCR, where flows are laminar. 52 

### Sootblowers, used to control ash plugging on full-scale SCRs, do not work effectively on small scale tests, allowing ash accumulation. 53 

### The one studythat includedNorth Dakota lignite54 

### used apitchthat was too small for the ash loading and ash characteristics, causing plugging.55 

### This study, which collected slip stream samples

50 See, e.g., S. Pritchard and others, Optimizing SCRCatalyst Design and Performance for Coal-Fired Boilers, Presented at EPAIEPRI 1995 Joint Symposium, Stationary Combustion NOx Control, May 16-19, 1995; StevenA. Benson, Ash Impacts on SCR Catalyst Performance, Slides, February 21,2006, BEPC_002065; S.A. Benson and others, Ash and Mercury Behavior in SCRCatalysts when Firing Subbituminous and Lignite Coals, Submitted to Fuel Processing Technology, BEPC_003820; S.A. Benson and lH. Pavlish, SCR Catalyst Performance in Flue Gases Derived from Subbituminous and Lignite Coals, Fuel Processing Technology, v. 86, no. 5, February 25, 2005, pp. 577-613, BPEC_003785; Y. Zheng and others, Deactivation ofV205-W03-Ti02 SCRCatalyst at Biomass Fired Power Plants: Elucidation of Mechanisms by Lab- and Pilot-Scale Experiments, Applied Catalysis B: Environmental, v. 83,2008, pp. 186-194, etc.

51 5/6/08 Cochran (CERAM) Email, p. I ("CERAM has experience with the slipstream test reactor used for testing at Baldwin and can confirm that this reactor is susceptible to ash accumulation due to wall effects.") in 5/8/08 Milton R. Young Additional Information.

52 A. Kling and others, Alkali Deactivation ofHigher Dust SCR Catalysts used for NOx Reduction Exposed to Flue Gas from 100 MW-scale Biofuel and Peat Fired Boilers: Influence ofFlue Gas Composition, Applied Catalysis, 2007; E-mail from Flemming Hanson, HaldorTepsoe, to Phyllis Fox, P.E., Re: Benson et a1. 2008, January 15,2008("I believe that when everything becomes more compactyou are more sensitive to wall cooling, shorter distances between turns and supports and ammonia injection. That doesn't mean that ash couldn'tbuild up on a full scale SCRas well, but instead ofa foot in distance between the turning vanes and the catalyst it may be 20 feet. A lot ofash problems arise because the ash is not hitting the catalyst channels parallel but at an angle. The lee side will build up ash.")
53 5/5/08 Email fromFlemmingHansen.HaldorTepsoe.toRobertBlakleY.Bums&McDonnell.Re: Comments to SCR Technology at MRYS Units 1&2, May 5, 2008 ("It is well known that soot blowing is difficult in pilot scale due to edge effects but also due to the dimensions ofthe soot blowertubes 

### O. Orifices have to be smaller compared to full scale in orderto distribute the soot blower air. As a consequence the soot blower should be moved closer to the catalyst in orderto obtain the same dynamic pressure at the catalyst surface which makes it difficult to actually cover the entire catalyst surface."), in 5/8/08 Milton R. Young Additional Information.

54 S.A. Benson and lH. Pavlish, SCR Catalyst Performance in Flue Gases Derived from ·Subbituminous and Lignite Coals, Fuel Processing Technology, v. 86, no. 5, February 25, 2005, pp. 577-613, BPEC 003785.

55 Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Additionallnformation and Discussion ofVendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination for Milton R. Young Station Units I & 2, Appendix A, Vendor Emails, Email from John Cochran, CERAM Environmental, Inc., to Robert Blakley, Re: Request for Lignite SCRFeasibility Commercial and Technical Information, May 6, 2008 ("CERAM has experience with the slipstream test reactor used for testing at Baldwin and can confirm that this reactor is susceptible to ash accumulation due to wall effects. Additionally, the 6 mm pitch Haldor T0psoe catalyst used for the Coyote Station testing [the ND lignite site] was an inadequate choice considering the ash loading and ash characteristics. Consideringthis choice ofcatalyst pitch and use ofthis slipstream reactor the results cannotbe assumed to be representative ofa full scale application. Based on the ash loading and chemistry for Milton R. Young Units I and 2 we would consider that at least a 7.4 mm pitch catalyst be utilized. A more conservative approach would be to

15

### from one lignite (Coyote) and two PRB-fired boilers (Baldwin, Columbia Station), predictedthat SCRcatalyst atthe PRB-fired Baldwin Stationwould deactivate rapidly.56 Subsequently, a full-scale SCRwas installed at Baldwin and has notexperienced any of the problems anticipated by the slipstreamtests. BEPC and its consultants were aware of this and made their arguments anyway.57 Finally, there is a long history ofapplicants arguing that SCRis nottechnically feasible on every new coal that is proposed, dating backto the 1980s. In each case, industry arguesthatplugging andpoisoning will occur due to unique characteristics ofits coal. In the early 1990s, U.S. industry argued SCRwould not work with "unique"U.S. bituminous coals, in spite ofwide-scale, successful SCRapplication inJapan and Germany.58 Today, there are 100,000 MW ofsuccessful SCRs operating onU.S. bituminous coals, including many with high sulfur. Next, in the late 1990s, industry argued that SCR would be overcome by plugging and poisoning when used on Powder River Basin (PRB) coals, raising many ofthe same concerns advanced by Sargent & 

### Lundy for North Dakota lignite. The slipstream studies that Sargent & 

### Lundy relies onpredict poorperformance for PRB coals,justas they do for lignites. However, today, there are over 25,000 MWofSCR installed on PRB coal, starting in 1999 with the New Madrid cyclone boilers (2x660 MW).59 In fact, some of the lowestNOx 

### emissionsrates inthe industryhave been achieved on PRB-coal fired boilers (e.g., Pleasant Prairie, Parish), in spite ofindustry's dire predictions to the

use either an 8.2 or 9.2 mm catalyst. This could have alleviated the noted test element ash pluggage issues.")

56 S.A. Benson et ai, SCR Catalyst Performance in Flue Gases Derived from Subbituminous and Lignite Coals, Fuel Processing Technology, v. 86, 2005, pp. 577-623.

57 E-mail from Carl Weilert, Bums & McDonnell, to John Shultz, BEPC,Re: B&McD Comments on SCR Presentation, February 17,2006, BEPC_001410 ("Our concern is that the Baldwin Station eventually did install full-scale high-dust SCR, and they seem to be working OK. These slides needto be used to illustrate that there was a significantly worse problem at Coyote than at Baldwin, or else the "opposition" can argue that the slip stream tests are invalid as a predictor ofperformance ofa full-scale SCR.") and S.A. Benson, Ash Impacts on SCR Catalyst Performance, Slides Presented to North Dakota State Health Department, February 21, 2006, p. 19.

58 Leslie L. Sloss and others, Nitrogen Oxides Control Technology Fact Book, Noyes Data Corp., Park Ridge, New Jersey, 1992, Chapter 5; H. ChristopherFrey, Engineering-Economic Evaluation ofSCRNOx Control Systems for Coal-Fired Power Plants, Proceedings ofthe American Power Conference, v. 57-11, April 1995, pp. 1583-1588.
59 5/26/08 Cochran (CERAM) Email, p. I ("The concerns presented are similar in argument to those that were used 10 years ago against the application ofPRB for high dust applications. The results ofthe cited test reactor work for Baldwin and Columbia would even seemingly indicate that the use ofhigh dust SCR on PRB applications would be similarly difficult to an installation on a lignite application. Meanwhile, dating from 1999 starting with the New Madrid project

### 0 there has been in excess of25,000 MW ofSCR installed on PRB fueled cyclone, wall, and tangential fired units with good success."); Letter from Eric N. Balles, Senior Vice President, Babcock Power Inc., to Glenn Shankle, Executive Director, TCE, Re: Response to SOAH Proposal for Decision, August 30, 2006 ("BPI has been involved in the development and early installation ofthe first Powder River Basin (PRB) fired SCR installation where many ofthe same concerns existed for SCR. The patented BPI Delta Wing SCR system was installed and its operation has consistently met or exceeded the NOx reduction guarantee.")



### 16

### contrary due to ash and alkaline poisons, the very culprits pointed to by Sargent & Lundy for North Dakota lignites. Currently, industry is arguing that SCRis nottechnically feasible orcosteffective on lignite coals, even thoughthere are successful lignite applications in Europe and inthe United States onTexas lignites (Sandow4, Oak Grove 1&2), withmore planned (Martin Lake 1-3). In fact, every coal is unique. CouFc0n tests and small scale reactorsare commonlyused to aid inthe design ofSCRs. 0 

### The SCRcatalyst is routinely formulated for each unique coal and application. North Dakota lignite is no different. As any coal, North Dakota lignite has unique challenges, but as the vendors indicate, these can be accommodated byproper design and catalystformulation.61


### b. Catalyst Lifetime
An SCRcatalyst must be changed outperiodically. The catalystlifetime is a function ofcatalyst activity and ammonia slip. As catalyst activity decreases overtime, ammonia slip increases until it reaches the design limit, typically 2 ppm, at whichpoint new catalyst is added. Catalyst lifetime is a designparameterthat is usually specifiedby the purchaser and guaranteed bythe catalyst vendor for the first three years of operation. 62 

### Sargent & Lundy assumed a catalyst lifetime of6 months to 1year, which amounts to about4,400 hours to 8,700 operating hours. 63 

### This arbitrarily selected and upsupported lifetime is very low for SCR catalyst, which is typically specified to last 16,000 to 24,000 hours for hot-side (orhigh-ash) SCRs (afterthe boiler), the worst-case location for catalyst life. In the tail-end position, after ash and catalystpoisons have been significantly reduced by pollution control devices, SCRcatalyst lasts 50,000 to over 100,000 hours.64 

### The erroneously assumed shortcatalyst lifetime is one ofthemajor drivers ofSargent & 

### Lundy's significantly overestimated operating costS.65

60 See, e.g., Noel Rosha and others, St. Johns River Power Park 2 x 670 MW SCR- Designed to Ensure Fuel Flexibility, Mega Symposium, 2008.

61 See, e.g., Letter from Michael G. Phil1ips, Aistom, to Robert Blakley, Bums & McDonnell, Re: Request for SCR Information Milton R. Young Units 1&2 ,May 30, 2007, p. 1("ND lignite does create many challenges for SCRs, but even with all those challenges, it is possible to use ND lignite ifthe system is designed properly

..."), p. 2 ("Fuels high in sodium and potassium require special selection ofcatalyst, but can be treated by SCR.") in 5/8/08 Milton R. Young Additional Information.

62 Cost Manual, SCR Section, pp. 2-46

- 2-47.

63 5/28/09 S&L Cost Analysis, p. 7.

64 See, for example, vendor e-mails in Appendix D ofthe NDPH Report: Selective Catalytic Reduction (SCR) Technical Feasibility for M.R. Young Station; McIlvaine, Next Generation SCRChoices

- HighDust, Low-Dust and Tail-End, FGD & DeNOx Newsletter, no. 369, January 2009; Hans Hartenstein, Steag's Long-Term SCR Catalyst Operating Experience and Cost, EPRI SCR Workshop, 2005.

65 Sargent & Lundy Spreadsheets



### 17

### The excessively short catalyst lifetimes assumed in the Sargent & Lundy cost analysis are contradictedby vendorproposals for a nearly identical application at the Milton R. Young Station, which bums a similarNorthDakota lignite in similar cyclone boilers. An exhaustive review ofcatalyst lifetime in that case, based onproposals from three separate vendors requested by two separate parties, indicates vendors estimated an initial catalyst lifetime guarantee of24,000 operating hours withtwo active and one spare layer ofcatalyst inthe lowdust ortail-end position. At the end ofthe first 24,000 hours, a newthird layerofcatalyst wouldbe added to the spare or empty layer. The first replacement layer would not be needed for about 88,000 hours or about 11 

### years ofSCR operation. 66 

### Thus, my revised cost analysis assumes a catalyst lifetime of24,000 operating hours (Ex. l, Cell E4l).

c. Number ofCatalyst Layers The catalyst volume required to achieve a givenNOx 

### level is typically divided into layers that canbe separately replaced. Most SCRdesigns include an empty layer that canbe filled with catalyst as the need arises. The most common configuration is two active layers with one spare. Initially, two layers are filled with catalyst. The third layer is added atthe end ofthe guarantee period, after 24,000 operating hours. Sargent & Lundy's calculations assume that 100% ofthecatalyst is replaced at the end ofvery short lifetimes, 6 months to 1year, and is silent as to layers. 67 

### Apparently, they have assumed one active and no spare layer. This is an overly conservative assumptionthat is notused to design modem SCRs. The vendorproposals contemplatedtwo active layers ofcatalystwith one spare. The catalyst replacement cost is estimated by dividing the total catalyst costbythe number oflayers. 68 

### I assumed initially two filled and one empty layer in my revised cost calculations (Ex. 1, Cell E42). d. Time Value ofMoney The Sargent & 

### Lundy calculations did not considerthe time value ofmoney in estimating catalystreplacement cost. 69 

### The Cost Manual explains that the future worth factor should be used to amortize catalystcost overthe years preceding the actual catalyst purchase. As money is allocated in advance ofpurchase, the sum ofthe annual catalyst replacement costis less than the purchase price ofthe.catalyst. Thus, the purchase price

66 Hartenstein Report, April 2010, pp. 10-23. See, for example, p. 14 ("In CERAM's budgetary catalyst proposal dated 10/13/2009 CERAM clearly specifies for: TESCRs [tail end SCR] at M.R. Young's Units 1 and 2 an initial catalyst design life of24,000 hours followed by the addition ofa third catalyst layer at that time. CERAM then expects that the first catalystreplacement doesn't occur until about 88,000 hours or about II years ofSCR operation. The second catalyst replacement isn't needed until approximately 125,000 hours or almost 16years ofSCR operation."), p. 22 ("In summary it can be statedthat none ofthe three (3) catalyst suppliers had any issues providing an initial catalyst life guarantee of24,000 operating hours in response to my own Request for Proposal.").

67 5/28/09 S&L Cost Analysis, p. 7 and Sargent & Lundy Excel Spreadsheets.

68 Cost Manual, SCR Section, Eqn. 2.50, pdf489.

69 5/28/09 S&L Cost Analysis, p. 7 and Sargent & Lundy Excel Spreadsheets.



### 18

### should have beenmultiplied by a future worth factor. Assuming an interest rate of7%, a catalyst life of24,000 hours, and a capacity factor of86.5%, the future worth factor is 0.31.70 In otherwords, the cost ofcatalystreplacement should be as little as one third of what Sargent & Lundy assumed based onthis factor alone (Ex. 1, Cell E43).

e. Unit Catalyst Cost Sargent& Lundy assumed a costof7,500 dollars per cubic meter ofcatalyst ($/m\71 

### This is very high compared to values typically quoted by vendors, $4,500/m3

­ 

### $6,500/m3

, 

### depending upon volume per order. 72 

### While I believe $7,500/m3 

### is high, I have not modifiedthis value in myrevised calculations as I do nothave access to specific vendor quotes for this application due to confidentiality claims. Sargent & Lundy should supporttheir assumed value or lower it appropriately (Ex. 1, Cell E33). f. Catalyst Volume Sargent & Lundy assumed a catalystvolume of530 m3in its cost calculations.73 The spreadsheets produced in response to EPA's Section 114 request indicate thatthis figure was derived by arbitrarily increasing a catalyst volume of440 m3by 20%.74 The source ofthe starting point, the 440 m3andthe 20% adjustment, are notdisclosed. As noted by EPA in its comments on the draft Regional Haze SIP, the value of 530 m3is high for a tail end SCR. Typically, cyclone fired units require about 1.5 m3of catalyst perMWfor a high dust SCR, while tail end SCRs require less thanhalfthe catalyst volume ofa high dust SCR.75 Thus, one would expect a catalystvolume ofabout 330 m3

. Therefore, Ihave used the unadjusted catalystvolume of440 m3from Sargent & Lundy's spreadsheets as a potential upperbound (Ex. 1, Cell E35).

70 Cost Manual, pdf489-490, Eqn. 2.52: FWF = 0.07[ 1/(1.073 -I)] = 0.31. Y = 24,000 hr/(8760)(0.865) = 3.2, rounds to 3. 71 5/27/09 S&L Cost Analysis, p. 7.

72 Letter from Callie A. Videtich, Director, Air Program, EPA Region 8, to Terry O'Clair, Director, Division ofAir Quality, North Dakota Department ofHealth, Re: EPA Region 8 Comments on December 2009 Draft Regional Haze SIP (Public Comment Version), January 8, 2010, Enclosure 2, p. 28; Email from Anthony C. Favale, Director

- SCRProducts, Hitachi Power Systems America, Ltd., to Anita Lee, U.S. EPA, Region 9, Re: CX Catalyst Question, April 1,2010 ($5,500/m3to $6,000/m\ Email from Flemming Hansen, Manager SCRDeNOx Catalyst, HaldorTopsoe, to Phyllis Fox, P.E., Re: Catalyst Cost, January 23,2008 ($6,000/m\ 735/27/09 S&L Cost Analysis, p. 7. 74 See, e.g., Sargent & Lundy spreadsheet: low-high dust scr-Ieland 01d2

- Sens2-cat life_05109.xls, cell E25 (440x1.20). 75 1/8/10 EPA Comments, Enclosure I, p. 27.

19

### g. Catalyst ChangeoutTime Sargent & 

### Lundy assumed an outage of 1to 4 weeks would be required to change outthe catalyst every 6 months to a year, as major scheduled outages occur only every 3 years.76 

### This is unsupported and inconsistent with the long history ofSCR operation in both Europe and the United States. First, a special outage to change outthe catalystwould not be required. The catalyst canbe changed out during scheduled major outages, which occur every 3 years. The first catalyst change would occur 3 years after installation. Thus, careful planning would alignthe first and subsequent changes with major outages, requiring no lost generation charges. Second, 1to 4 weeks to change out the reported catalyst volume is excessive. The estimated catalyst exchange rate for a tail-end SCR onthe similar Milton R. Young units was 2.2 days for Unit 1 (257 MW) and 3.8 days for Unit 2 (477 MW).77 Based on these values, the proportional exchange time for Leland Olds is 3.6 days. This is generally consistent with industry experience. Alternatively, as the boiler is typically down for cleaning 3 to 4 times peryear for a period ofabout 4 days each time, this downtime would be sufficient to exchange a layer should one be required before a major outage. SCR systems are designed to minimize unit downtime to minimize operating costs. Thus, I assumed there would be no lost generation during catalystreplacement as it would beprudent design and operating practices to schedule these events during routinely scheduled maintenance outages (Ex. 1, Cell E73). 

### B.3 Cost ofUtilities and Supplies Sargent & 

### Lundy evaluated a range ofcosts for ammonia, the reagent used in the SCR, and natural gas, used to reheat the flue gas. 78 

### The range ofcosts includes those that may occur in the future. Speculation about future commodity prices is inconsistentwith cost effectiveness methodology, which is based onthe current annualized cost without escalation. The Cost Manual approach, recommendedby the BART Guidance, explicitly excludes future escalation as cost comparisons are made on a current real dollarbasis. Inflation is not included in cost effectiveness analyses as they rely on the most accurate information available at currentprices and do not try to extrapolate those prices into the future. 79

76 5/27/09 S&L Cost Analysis, p. 5.

77 Hartenstein Report, April 20I0, p. 36.

78 5/27/09 S&L Cost Analysis, p. 7.

79 See, e.g., Cost Manual, p. 2-36, pdf50.



### 20

### a. Ammonia Ammonia is injected into the flue gas ahead ofthe SCRcatalystto react with NOx 

### and convert it to nitrogen gas and water. The Sargent & Lundy cost analyses evaluated ammoniacosts of$450/ton and $700/ton.80 Recent BART analyses have used values closerto the lower end ofthis range. Black & Veatch, an engineering firm that designs SCRs, used an anhydrous ammonia cost of$450/ton in a September 2010 BART analysis for Boardman.8l Sargent & Lundy used an anhydrous ammonia costof$475/ton in a September 2010 BART analysis for the Navajo Generating Station.82 Thus, in my revised cost analyses, I used $475/ton for the cost ofammonia (Ex. 1, Cell E20). b. Natural Gas The temperature ofthe flue gas exiting the wet scrubber is raised to SCR operating temperature by first sending itto a gas-gas heat exchanger and thento a natural gas fired ductburner (Fig. 1). This is typically the most significant operating cost for a tail-end SCR. The Sargent & 

### Lundy cost calculations assume it would take 115 MMBtulhr ofnatural gas83 to raise the flue gas temr,erature from 550 F to 600 F at a natural gas price of$8.0/MMBtuto $12.0/MMBtu. 4 

### There are three problems with these assumptions that significantly overestimate reheat cost. First, steam has important advantages over natural gas including lower cost, no increase in flue gas flow rate from gas combustion byproducts, no moisture condensation onthe catalyst, and no risk ofre-vaporization ofcatalystpoisons in the flame ofa duct burner. Mosttail end SCRs in Europe use steam for reheating.85 Vendors in the Milton R. Young case uniformly recommendedthe use ofa steam coil in place ofnatural gas fired duct burners.86 Sargent & Lundy did not evaluate a steam coil. The annual cost of using steam, for example, could be estimated from the amount ofsteam required to generate a megawatt (MW) ofelectricity at Leland Olds and the bus barprice per MW for the plant. This information has notbeen produced by eitherBEPC or Sargent & Lundy, precluding an independent calculation. However, atypical live steam loss of 2%87 would reduce generating capacity by 0.02x440 

### = 8.8 MW. Assuming $35/MWh and a 86.5% capacity factor, this amounts to $2.3 million in reheat costs, much lower

80 5/27/09 S&L Cost Analysis, p. 7. 81 Black & Veatch, Portland General Electric Boardman Plant, Best Available Retrofit Technology (BART)/Reasonable Progress Analysis Revision 3: Boardman 2020 Alternative, August 27,2010, Table 2­ 2. 82 Sargent & Lundy, Salt River Project Navajo Generating Station

- Units 1,2,3, SCR and Baghouse Capital Cost Estimate Report, Revision D, August 17,2010, pdf58, Table 9-2. 83 5/27/09 S&L Cost Analysis, p. 5 (115 MMBtu/hr). 84 5/27/09 S&L Cost Analysis, pp. 3 (550 F - 600 F), 7 ($8/MMBtu - $12/MMBtu). 851/8/10 EPA Comments, Enclosure I, p. 25. 86 See, e.g., Hartenstein Report, April 20I0, pp. 34-35,40-43, 87 Hartenstein Report, April 2010, p. 40.



### 21

### thanthe $7.4 to $11.2 million for natural gas estimated by Sargent & 

### Lundy (Ex. 1, Row 72). 

### Second, the duct burner firing rate of 115 MMBtulhr assumes the flue gas would be heated from 550 F to 600 F, orby 50 F. This is excessive. Operating experience with numerous tail-end SCRs in Europe overthe past 20 years indicates that an increase of 20 to 25 F is adequate.88 This would lowerreheat costs by a factor of2.5. Further, an SCR operating temperature of525-550 F is sufficient for a tail-end SCR as the flue gas S02 concentrations afterthe wet scrubberare low, eliminating the concern with deposition of ammonia salts onthe catalyst.89 The natural gas firing rate of 115 MMBtulhris high comparedto an estimate of66.4 MMBtulhrmade by Bums & 

### McDonnell for tail-end SCR onLeland Olds Unit 2.90 The Bums & 

### McDonnell estimate is consistent with European experience. Thus, I use it in my revised cost analysis (Ex. 1, Cell E26). Third, the assumedprice ofnatural gas price, 

### $8/MMBtuto $

### 12/MMBtu, is excessive and is based on historic price spikes. BART costeffectiveness analyses are based onthe best estimate ofcurrent costs at the time ofthe analysis and do not consider future escalation. As cost effectiveness is determined relative to other similar sources, future escalation in gas prices would affect all natural gas users, notjustLeland OIds. The most recent datareported to the Energy InformationAgency (ErA) indicates thatthe cost ofnatural gas to electric power consumers inNorth Dakotahas ranged from $4.48IMMBtu (October 2010) to 

### $5.37/MMBtu (June 2010).91 As very**littl~** 

### natural gas is currently used in North Dakota, a more reasonable estimate for a dedicated supply is the Henry Hub spotprice plus transportation cost. The 2010 Henry Hub price ofnatural gas is 

### $4.37/MMBtu. 92 

### The expected Henry Hub natural gas spotprice for 2011 is 

### $4.16/MMBtu, or $0.211MMBtu lowerthan 2010. The EIA expects the natural gas marketto beginto tighten in 2012, with the Henry Hub spotprice increasingto an average 

### of$4.58/MMBtu. 93 

### Transportation cost is typically less than $lIMMBtu. Thus, a reasonable estimate for purposes of2010 BARTis about 

### $5.5/MMBtu (Ex. 1, Cell E28).

88 Hartenstein Report, April 2010, p. 40.

89 McIlvaine, Next Generation SCRChoices

- High-Dust, Low-Dust and Tail-End, FGD & DeNOx Newsletter, No. 369, January 2009; 5/6/08 Cochran (CERAM) Email, p. 2 ("Ammonia should not be injected below the minimum operatingtemperatures (MOT). Based on the S02to S03 reported the MOT would be approximately 600 F. For lower sulfurfuels [such as NO lignite] and/or reducedNOx removal performance a lower MOT wouldbe possible. Additionally, briefperiods ofopemtion below the MOT would be possible without permanent degradation. In no event would any ammoniabe allowed to be injected below 530 F for any likely combination ofreasonable sulfur and NOx removal parameters."), in 5/8/08 Milton R. Young Additional Information.

90 Bums & McDonnell, Technology Feasibility Analysis and Cost Estimates for Leland aIds Station Unit 1 and 2, Basin Electric PowerCooperative, Final Draft, December2005, p. 86.

91 EIA, Natural Gas Monthly:http://www.eia.doe.gov/oil_gas/natural_gas/datayublications/natural_gas_monthly/ngm.html.

92 http://tonto.eia.gov/dnav/ng/hist/mgwhhda.htm.

93 http://www.eia.doe.gov/analysis/ and http://www.eia.gov/emeu/steo/pub/contents.html.



### 22c. Power An SCRincreases powerdemand for auxiliary equipment, including the induced draftfans usedto overcomethe increase inbackpressure from the SCRplus electricityto runthe ammonia system, dilution airblower, dilution air heaters, and seal airfans. Thus, auxiliary power is the electricityrequiredto runthe plant, or electricity not sold. This cost is estimatedby multiplying the electricity demand in kilowatts bythe cost ofelectricity in dollars permegawatthour (MWh). Sargent & Lundy estimated auxiliary power cost assuming 6,956 kW (Ex. 1, Tab: Power) priced at $50/MWh.94 Cost effectiveness analyses are based onthe costto the ownerto generate electricity, orthe busbar cost, notmarketretail rates. The unit cost ofelectricity used by Sargent& Lundy, $50/MWh, is highfor a lignite-fired boilerbuiltnear its fuel source. Bums & McDonnell assumed $38/MWhin the 2005 Feasibility Analysis for Leland Olds95 and $35/MWhfor Milton 

### R. Young Unit 1.96 I usedthe value Burns & McDonnell reported for Leland Olds (Ex. 1, Cell E24). Thebusbar costfor Leland Olds should be providedby BEPC and the power costsrevised as necessary. 

### B.4 Capacity Factor The capacity factor is the fraction ofthe available capacitythat is actually used. It is calculated as the ratio ofthe actual electrical outputto its full capacity, typically over a year. The emissionreductions and variable O&M costs are bothdirectlyproportional to the capacity factor. The higherthe capacity factor, the largerthe emissionreductions and the higherthe variable O&M costs. The BART Guidelines indicate that: "inthe absence ofenforceable limitations, you calculatebaseline emissions based upon continuation ofpastpractice.,,97 The Sargent & Lundy analysis calculatedthe capacity factor assuming the unit would operate at full capacity at all times except during catalyst changeouts. Thisresulted incapacity factors of92%to 96%, which are higherthan operating experience. Themonthly CleanAirMarkets datafor Leland Olds Unit 2 indicates thatthe gross electrical outputfor the baseline period98 is 3,334,426 MWh. Therated**capacit~** of Leland Olds Unit 2 is 440 MW. Thus, the capacity factor is 86.5% (Ex. 1, Cell E38). 9

94 5/27/09 S&L Cost Analysis, p. 7 and Sargent & Lundy Excel Spreadsheets, Power Tab.

95 Bums & McDonnell, Technology Feasibility Analysis and Cost Estimate for Leland Olds Station Unit 1 and 2, Basin Electric Power Cooperative, Final Draft, December 2005, p. 86.

96 Bums & McDonnell, NOx Best Available Control Technology Analysis Study

- Supplemental Report for Milton R. Young Station Unit 1, Minnkota Power Cooperative, Inc., November 2009, p. 4-42.

97 70 FR 39167 (July 6, 2005).

98 The baseline period is the highest 24-consecutive month average NOx emission rate during calendar years 2000-2004, or March 2001

- February 2003.

99 Capacity factor = 3,334,426 MWh/[(440)(8760)] = 0.865.

23

### This value was used to calculateNOx 

### emission reductions (Ex. 1, Cell E18) and variable O&M Costs (Ex. 1, Cells E69

- E72). 

### C. NOx 

### EMISSION REDUCTION The 5/27/09 Sargent & Lundy Cost Analysis calculated cost effectiveness by dividing the "levelizedtotal annual cost," consisting ofthe sum ofannualized capital cost and levelized O&M cost, by the total annual NOx 

### emission reduction of 10,571 ton/yr, from an uncontrolled baseline. The basis ofthese NOx 

### reductions was not disclosed.
In my calculations, I assume SCRplus ASOFA reduced baseline NOx 

### emissions ofO.67lb/MMBtuIOO 

### to 0.05 Ib/MMBtu (Ex. 1, Cell E18). An SCRoutletNOx 

### emission rate of0.05 Ib/MMBtu can be readily achievedby SCRplus ASOFA. 

### The 5/27/09 S&L analysis and supporting spreadsheets assumedthe combination achieved 0.05 Ib/MMBtu. The SCRwas specifically assumedto reduce NOx 

### from an inlet of0.48 Ib/MMBtu, a level consistent with performance ofLeland Olds Unit 2 since installation ofASOFA, to 0.05 Ib/MMBtu or90%NOx 

### control. 

### D. COST EFFECTIVENESS SUMMARY Myrevisions discussed above and summarized inExhibit 1improvethe cost effectiveness ofSCR plus ASOFA at Leland Olds from the range of$4,170/tonto $5,976/ton in 2009 dollars reported by Sargent & Lundy to $1,954/ton in 2010 dollars (Ex. 1a, Cell E80). The cost effectiveness ofSCR alone, after installation ofASOFA, is $2,609/ton (Ex. 1b, Cell E80). My revised cost effectiveness value is withinthe range of cost effectiveness values reported for other SCRBARTdeterminations 10I 

### and thus is per se cost effective. My estimate is an upper bound as the SCRcapital costs are based on a unit capital cost that is much higherthan actual experience from numerous installed SCRs. In my opinion, the actual cost effectiveness ofSCRalone and SCRplus ASOFA on Leland Old Unit 2 is lower, i.e., more costeffective, than calculated in Exhibit 1.

100 NDDH, BART Detennination for Leland Olds Station Units 1and 2, p. 24.

\0\ Jim Bridger Units 3 and 4: $2,258; Naughton Unit- 3: $2,830Iton; PGE Boardman: $3,096/ton; Four Comers: $2,515

- $3,I63/ton, San Juan: $1,549/ton to $2,016/ton; Big Stone 1: $825Iton; Hayden Units I and 2: $3,385

- $4,064. Some ofthese figures also include the installation costs for combustion controls.



### 24EXHIBIT 1a COST EFFECTIVENESS ANALYSIS TAIL-END SCR PLUS ASOFAAT LELAND OLDS UNIT 2 Row & Column Numbers --> E F G H I J Sargent & Lundy Cases Fox Revised Units Cost I H G F E INPUT DATA

10 Design Coal Lignite Lignite Lignite Lignite Lignite Lignite 11 SCR Configuration Tail End Tail End Tail End Tail End Tail End Tail End 12 Capacity MW 440 440 440 440 440 440 13 Heat Input MBtu/hr 5,130 5,130 5,130 5,130 5,130 5,130 14 Inlet NOx Emissions Ib/MMBtu 067 048 0.48 0.48 0.48 048 15 Outlet NOx Emissions IblMMBtu 005 16 Control Efficiency % 93 90 90 90 90 90 17 NOx Removed Iblhr 3,181 2,216 2,216 2,216 2,216 2,216 18 NOx Removed tonslyr 12,050 10,517 10,517 10,517 10,517 10,511 19 Ammonia Required Iblhr 1,253 873 873 873 873 873 20 Ammonia Cost $/ton 475 700 450 450 450 450 21 Pressure Drop across catalyst inw.c. 4 4 4 4 4 4 22 Pressure Drop inw.c. 18 18 18 18 18 18 23 Power Consumption kW 6,956 6,956 6,956 6,956 6,956 6,956 24 Power Cost $IMWh 38 50 50 50 50 50

Temperature Rise Across Steam to Flue 25 Gas Reheater F 50 50 50 50 50 50 26 Natural Gas Requirement MMBtu/hr 66 115 115 115 115 115 27 (30 F rise) (50 F rise) (50 F rise) (50 F rise) (50 F rise) (50 F rise) 28 Natural Gas Cost $/MMBtu 55 12.0 12.0 120 8.0 80 29 Unit Capital Cost SCR + SOFA+SI (2009) $/kW 388 388 388 30 Unit Capital Cost SCR + SOFA (2009) $/kW 376 376 376 376 31 Unit Capital Cost ASOFA (2009) $/kW 26 26 26 26 26 26 32 Unit Capital Cost SCR (2009) $/kW 350 350 350 350 33 Unit Catalyst Cost $/m' 7,500 7,500 7,500 7,500 7,500 7,500 34 35 Initial Catalyst Volume m' 440 530 530 530 530 530 36 Coal Cost $/MBtu 1.00 100 1.00 100 100 100 37 Catalyst Cost $ 3,300,000 3,960,000 3,960,000 3,960,000 3,960,000 3,960,000 38 Annual Capacity Factor % 86.5 92.3 92.3 92.3 92.3 962 39 Cost of Outage $lweek 0 3,696,000 3,696,000 3,696,000 3,696,000 3,696,000 40 Outage Duration weeks 0 4 4 4 4 2 41 Catalyst Replacement 24,000 hrs 6 months 6 months 6 months 6 months 12 months 42 Number ofCatalyst Layers 3 1 1 1 

# , 1 43 Future Worth Factor 031 1 1 1 1 1 44 Capital Recovery Factor 008718 0.08718 008718 008718 0.08718 008718 45 Levelized Annual O&M Factor 1 1.19314 119314 1.19314 1.19314 1.19314 46 47 TOTAL CAPITAL COST (2010) 48 49 SCR + ASOFA Capital Cost $ 175,561,000 170,720,000 170,720,000 165,440,000 165,440,000 165,440,000 50 SCR Capital Cost $ 164,121,000 51 S03 Mitigation Capital Cost' $ 0 0 0 0 0 0 52 53 Totallnstatled Capital Cost $ 175,561,000 170,720,000 170,720,000 165,440,000 165,440,000 165,440,000 54 Annual Capital Cost $/yr 15,305,408 14,883,370 14,883,370 14,423,059 14,423,059 14,423,059 55 56 57 FIXED O&M COST 58 59 Operating Labor Cost $/yr $0 $0 $0 $0 $0 $0 60 Maintenance Materials Cost $/yr $527,000 $512,000 $512,000 $496,000 $496,000 $496,000 61 Maintenance Labor Cost $/yr $351,000 $341,000 $341,000 $331,000 $331,000 $331,000 62 Administrative and Support Labor $/yr

I $0 $0 $0 $0 $0 $0 63 64 Total Fixed O&M Cost $/yr $878,000 $853,000 $853,000 $827,000 $827,000 $827,000 65 I 66 67 VARIABLE O&M COST 68 69 Ammonia Cosl $Iyr 2,255,000 2.471,000 1,589,000 1,589,000 1,589,000 1,655,000 70 Catalyst Cost $/yr 342,000 7,920,000 7,920,000 7,920,000 7,920,000 3,960,000 71 Power Cost $Iyr 2,003,000 2,813,000 2,813,000 2,813,000 2,813,000 2,930,000 72 Gas Penalty $Iyr 2,767,000 11,161,000 11,161,000 11,161,000 7.441,000 7,750,000 73 Outage Penalty $/yr 0 14,784,000 14,784,000 14,784,000 14,784,000 7,392,000 74 Sorbent Injeclion S/yr 0 207,000 207,000 207,000 207,000 207,000 75 76 Total Variable O&M Cost S/yr 7,367,000 39,356,000 38,474,000 38,474,000 34,754,000 23,894,000 77 40,209,000 78 TOTAL O&M COSTS S/yr 8,245,000 47,974,966 46,922,617 46,891,595 42,453,114 29,495,614 79 80 Cost Effectiveness $Iton 1,954 5,977 5,877 5,830 5,408 4,178

3/27/09 S&L Cost AnalysIs, Table 2,5-5 5,976 5,876 5,792 5,372 4,170 NOTES a The sorbent injection cost is included in the unit capital cost of $388/kW b Capital costs adjusted to 2010 dollars using the CEPCI index ofOctober 2010/2009 =556.2/521.9.EXHIBIT 1b COST EFFECTIVENESS ANALYSIS TAIL-END SCR PLUS ASOFA AT LELAND OLDS UNIT 2 Row & Column Numbers >""''j E F G H I J 

# + Sargent & Lundy Cases Fox Revised Units Cost I H G F E INPUT DATA

10 Design Coal Lignite Lignite Lignite Lignite Lignite Lignite 11 SCR Configuration Tail End Tail End Tail End Tail End Tail End Tail End 12 Capacity MW 440 440 440 440 440 440 13 Heat Input MBtu/hr 5,130 5,130 5,130 5,130 5,130 5,130 14 Inlet NOx Emissions Ib/MMBtu 0.48 0.48 0.48 0.48 0.48 0.48 15 Outlet NOx Emissions Ib/MMBtu 0,05 16 Control Efficiency % 90 90 90 90 90 90 17 NOx Removed Ib/hr 2,206 2,216 2,216 2,216 2,216 2,216 18 NOx Removed tonslyr 8,357 10,517 10,517 10,517 10,517 10,511 19 Ammonia Required Ib/hr 869 873 873 873 873 873 20 Ammonia Cost $/ton 475 700 450 450 450 450 21 Pressure Drop across catalyst inw.c. 4 4 4 4 4 4 22 Pressure Drop inw.c. 18 18 18 18 18 18 23 Power Consumption kW 6,956 6,956 6,956 6,956 6,956 6,956 24 Power Cost $/MWh 38 50 50 50 50 50

Temperature Rise Across Steam to Flue 25 Gas Reheater F 50 50 50 50 50 50 26 Natural Gas Requirement MMBtu/hr 66 115 115 115 115 115 27 (3D F rise) (50 F rise) (50 F rise) (50 F rise) (50 F rise) (50 F rise) 28 Natural Gas Cost $/MMBtu 5,5 12,0 12,0 120 8,0 80 29 Unit Capital Cost SCR + SOFA+SI $/kW 388 388 388 30 Unit Capital Cost SCR + SOFA $/kW 376 376 376 376 31 Unit Capital Cost ASOFA $/kW 26 26 26 26 26 26 32 Unit Capital Cost SCR $/kW 350 350 350 350 33 Unit Catalyst Cost $/m' 7,500 7,500 7,500 7,500 7,500 7,500 34 35 Initial Catalyst Volume m' 440 530 530 530 530 530 36 Coal Cost $IMBtu 1,00 1,00 1,00 1.00 100 100 37 Catalyst Cost $ 3,300,000 3,960,000 3,960,000 3,960,000 3,960,000 3,960,000 38 Annual Capacity Factor % 86,S 92,3 92,3 92,3 92,3 96,2 39 Cost of Outage $/week 0 3,696,000 3,696,000 3,696,000 3,696,000 3,696,000 40 Outage Duration weeks 0 4 4 4 4 2 41 Catalyst Replacement 24,000 hrs 6 months 6 months 6 months 6 months 12 months 42 Number of Catalyst Layers 3 1 1 1 1 1 43 Future Worth Factor 0,31 1 1 1 1 1 44 Capital Recovery Factor 008718 008718 0,08718 0,08718 0,08718 0,08718 45 Levelized Annual O&M Factor 1 1,19314 1,19314 119314 1,19314 1,19314 46 47 TOTAL CAPITAL COST 48 49 SCR + ASOFA Capital Cost $ 170,720,000 170,720,000 165,440,000 165,440,000 165,440,000 50 SCR Capital Cost $ 164,121,000 51 S03 Mitigation Capital Cost' $ 0 0 0 0 0 0 52 53 Total Installed Capital Cost $ 164,121,000 170,720,000 170,720,000 165,440,000 165,440,000 165,440,000 54 Annual Capital Cost $/yr 14,308,069 14,883,370 14,883,370 14,423,059 14,423,059 14,423,059 55 56 57 FIXED O&M COST 58 59 Operating Labor Cost $/yr $0 $0 $0 $0 $0 $0 60 Maintenance Materials Cost $/yr $492,000 $512,000 $512,000 $496,000 $496,000 $496,000 61 Maintenance Labor Cost $/yr $328,000 $341,000 $341,000 $331,000 $331,000 $331,000 62 Administrative and Support Labor $/yr $0 $0 $0 $0 $0 $0 63 64 Total Fixed O&M Cost $/yr $820,000 $853,000 $853,000 $827,000 $827,000 $827,000 65 66 67 VARIABLE O&M COST 68 69 Ammonia Cost $/yr 1,564,000 2,471,000 1,589,000 1,589,000 1,589,000 1,655,000 70 Catalyst Cost $/yr 342,000 7,920,000 7,920,000 7,920,000 7,920,000 3,960,000 71 Power Cost $/yr 2,003,000 2,813,000 2,813,000 2,813,000 2,813,000 2,930,000 72 Gas Penalty $/yr 2,767,000 11,161,000 11,161,000 11,161,000 7,441,000 7,750,000 73 Outage Penalty $/yr 0 14,784,000 14,784,000 14,784,000 14,784,000 7,392,000 74 Sorbent Injection $/yr 0 207,000 207,000 207,000 207,000 207,000 75 76 Total Variable O&M Cost $/yr 6,676,000 39,356,000 38,474,000 38,474,000 34,754,000 23,894,000 77 40,209,000 78 TOTAL O&M COSTS $/yr 7,496,000 47,974,966 46,922,617 46,891,595 42,453,114 29,495,614 79 80 Cost Effectiveness $Iton 2,609 5,977 5,877 5,830 5,408 4,178

3/27/09 S&L Cost AnalySIS, Table 2,5-5 5,976 5,876 5,792 5,372 4,170 NOTES a The sorbent injection cost is included in the unit capital cost of $3881kW b Capital costs adjusted to 2010 dollars using the CEPCI index of October 2010/2009; 556,2/521,9,

### SCR Power Consumption (High/Low Dust) High Dust Low Dust 

### Gross Power, MW 440 440 

### ID fans

Increase in Fan HP 3,625 8,157 Increase in Motor kW 2,705 6,085


### Ammonia System Power

Ammonia Consumption, lblhr 1091 873 Power Consumption, kW 109 87 2 x 20 kW Heaters 2 x 20 kW Heaters 

### Dilution AirBlower

Power Consumption, HP 128.0 102.0 Power Consumption, kW 95.5 76.1 ConnectedAir Blowers, kW 2 x 20 2 x20


### Dilution AirHeaters

Power Consumption, kW 387.1 309.7 Connected Heaters, kW 2 x 75 2 x 75


### AmmoniaPump

Power Consumption, HP 2.4 1.9 Power Consumption, kW 1.8 1.4


### SealAirFans

Power Consumption, HP 88 88 Power Consumption, kW 66 66 Connected Seal air fan, kW 2 x 125 2 x 125



### Sub-TotalPower Consumption, kW 3363 6625


### Electrical and ControlPower Consumption, kW 

### 168 331
TotalPower Consumption, kW 

### 3531 6956 % 

### ofGross 

### 0.80 1.58