# Cost of 

# NOx BART Controls on Utah EGUs to: 

# ECIR Incorporated 501 Eastowne Drive, Suite 250 Chapel Hill, NC 27514
May 13, 2016



## Andover Technology Partners 112 Tucker Farm Road, North Andover, MA 01845 phone: (978) 683-9599; e- mail : staudt@AndoverTechnology.com

# Andover Technology Partners 112 Tucker Farm Road, North Andover, MA 01845

# Contents

1. 2. 3. Sections Background 

### NOxControl Cost Methodology Estimated Costs Page 1 2 

### 19

# 1. Background Andover Technology Partners (ATP) under contract to EC/R, Incorporated provided cost estimates for Best Available Retrofit Technology (BART) for NOxcontrols at the following Utah Electricity Generating Units. • PacifiCorp Hunter 1 

### & 2 • PacifiCorp Huntington 1 

### & 2



### www.AndoverTechnology.com

# 2. NOx Control Cost Methodology ATP has developed cost estimates for the following Utah coal-fired units . • PacifiCorp Hunter Units 1 

### & 2 • PacifiCorp Huntington Units 1 

### & 2 For each unit, estimates of cost and cost effectiveness were made for the following technologies, where applicable: • New, advanced combustion controls that have been installed since 2007 • Selective Noncatalytic Reduction (SNCR) alone, but after installation of combustion controls • Selective Catalytic Reduction (SCR) alone, but after installation of combustion controls • Combustion controls in combination with SNCR • Combustion controls in combination with SCR Estimates were based upon an initial average annual NOx level equal to 2001-2003 historical rates (average of annual average for each of the three years) when new combustion controls were not in use at these units . Emission rates with new combustion controls were estimated from more recent data for those units with combustion controls . 2001-2003 historical data were also used to estimate annual heat input and the associated capacity factor for each unit. For each unit, SNCR and SCR costs were estimated in combination with new combustion controls . The units are equipped as follows: PacifiCorp Hunter Unit 1: Low NOx Burner Technology w/ Separated Overtire Air (OFA); installed 2014 1 

### PacifiCorp Hunter Unit 2: Low NOx Burner Technology w/ Separated OFA; installed 2011 2 

### PacifiCorp Huntington Unit 1 : Low NOx Burner Technology w/ Separated OFA; installed 2011 3 

### PacifiCorp Huntington Unit 2: Low NOx Burner Technology w/ Separated OFA; installed 20074 

### In estimating the cost of controls, the following were considered: • Integrated Planning Model (IPM) Cost models (version 5. 13) 5 

### • US EPA Air Pollution Control Cost Manual 6 

### • Data provided by PacifiCorp in their BART assessments 7

1 PacifiCorp BART Analysis of Hunter Unit 1 , July 2, 2012 ; pdf page 54; however, 2015 AMPD data i ndicates close-coupled OFA 2 PacifiCorp BART Analysis of Hunter Unit 2, June 7, 2012 ; pdf page 55 3 PacifiCorp BART Analysis of Huntington Unit 1 , June 26, 2012 ; pdf page 12; however, AMPD data still shows close-coupled OFA 4 PacifiCorp BART Analys is of Huntington Unit 2, June 26, 2012 ; pdf page 54 5 Sargent & Lundy, IPM Model - Updates to Cost and Performance for APC Technologies SNCR Cost Development Methodology Fi nal March 2013 Project 12847-002 Sa rgent & Lundy, IPM Model - Updates to Cost and Performance for APC Technologies SCR Cost Development Methodology Fi nal March 2013 Project 12847-002 6 EPA. 2002 . EPA Air Pollution Control Cost Manual (Sixth Edition) . EPA/452/B-02-001 ("the 2002 CCM " )

Chapter 1 , Selective Noncatalytic Reduction , -6/5/2015 - Draft for Publ ic Comment ("the 2015 SNCR CCM " ) Chapter 2 Selective Catalytic Reduction , -6/5/2015 - Draft for Publ ic Comment ("the 2015 SCR CCM " ) 7 PacifiCorp' s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014 

### www.AndoverTechnology.com• Data provided in comments to the State of Utah 8 • Other data that have been published and are described in more detail in this report The BART guidelines recommend use of the 2002 EPA Air Pollution Control Cost Manual, and the methodology used here for estimating costs is consistent with the recommendations in the manual. The overnight cost methodology does not allow for inclusion of financing costs during construction (also called AFUDC) . Capital costs were adjusted to 2014 costs using the Chemical Engineering Plant Cost Index (CEPCI) for capital costs and current reagent cost estimates were collected . The cost of power used for auxiliary loads equals expenses per net kWh as reported in 2014 FERC Form 1 data for PacifiCorp. 9 Capacity factors used in cost estimates were estimated from historical US EPA Air Markets Program Data 10 for the four units. Reagent costs are from a recent estimate.11 Detailed cost estimates are provided in the Microsoft Excel Workbooks that are provided with this report:

• Microsoft Excel Workbook UT EGU BART_ Costs_2016_RTC_20 year.xlsx, and • Microsoft Excel Workbook UT EGU BART_ Costs_2016_RTC_30 year.xlsx Combustion Controls For combustion controls, capital and operating and maintenance cost estimates provided in PacifiCorp's August 2014 estimate were used. The installation of combustion controls were completed prior to the August 2014 PacifiCorp report. Percent reduction and tons of NOx removed were based upon actual emission rates reported to EPA's Air Markets Program Data from 1) 2001-2003, and 2) after installation of new combustion controls using data from 2014 and 2015. The costs are shown in the worksheet NOx-LNB in the two Microsoft Excel workbooks provided with this report .

PacifiCorp BART Analysis of Hunter Un it 1 , July 2, 2012 PacifiCorp BART Analysis of Hunter Un it 2, June 7, 2012 PacifiCorp BART Analysis of Huntington Unit 1, June 26, 2012 PacifiCo rp BART Analysis of Huntington Unit 2, June 26, 2012 8 National Park Service Comments and attachments; May 1 , 2015

HEAL UTAH* NATIONAL PARKS CONSERVATION ASSOCIATION * SIERRA CLUB ; Comments on Proposed Amendments to Utah ' s Reg ional Haze Ru le ; December 22 , 2014 and December 18, 2014 Technical Support Document 9 PacifiCorp FERC Form 1 , Quarter 4, 2014, pages 402 . 1 , 403 . 1 , 402.2 , li ne 35 10 http ://ampd .epa.gov/ampd/ 11 9/23/15 email from Fuel Tech, cos t of $1.60 per gallon 25% to 30% less for prill. www.AndoverTechnology.com

### SNCR For SNCR the capital cost provided in PacifiCorp's August 2014 estimate was used, excluding AFUDC. The cost analysis for SNCR are shown in the worksheet NOx-SNCR in the two Microsoft Excel workbooks provided with this report. SNCR reagent consumption and the level of NOxreduction are very dependent upon a number of factors - such as initial NOxlevel and furnace temperatures . Figure 1 is an example of test data from an SNCR optimization program on a pulverized coal-fired boiler that shows NOxreduction and chemical utilization versus Normalized Stoichiometric Ratio (NSR - a measure of chemical treatment rate). Chemical utilization equals per cent reduction divided by NSR and is a measure of the efficiency of reagent use. The figure includes data from optimized as well as unoptimized configurations, which is why some of the data points fall below the curves. The curves that would be developed for any given unit will vary from one unit to another and, while having similar shapes as those in Figure 

### 1, may have somewhat different values based upon temperature and baseline NOx .
70% 60% 50% 

# 5 40% 

### c ) 30% 20% 

# • 10% 0% 0 0.5 1 .5 2 2.5 NSR 

### Figure 

### 1. NOx Reduction and Reagent Utilization versus reagent treatment rate in NSR for a Pulverized Coal -Fired Boiler during an SNCR optimization program 12 Data points plotted below the curves are at unoptimized conditions .

12 Staudt, J.E., Kehrer, K., Poczynek, J., Cote, R., Pierce, R., Afonso , R., Miles, D., and S load , A., " Optim izing Selective Non-Catalytic Reduction Systems for Cost-Effective Operation on Coal -Fired Electric Utility Boilers", presented at ICAC Forum '98, Durham , NC, March 19-20, 1998. www.AndoverTechnology.comFigure 

### 2. NOx reduction versus baseline NOxfor coal-fired EGUs 13 

## SNCR Reduction vs "Inlet" NOx Level for Coal-fired EGUs (Subset of 

# aU data)

40
-______..._ ...............·-···--·..---·--···-···········-········· ·······--·-····--·--·····-·······..····..·-·-·• -····--..········-·-······-···· • ..······..--···..--..··-······

### ~ 35
-------- • ---·

### ~ 

### ' t i; 30 

### +----------------<-.-t=--------- QJ a: x 0 25 +----- 

### z 20
0 0. 2 0.4 0.6 0. 8 1 Inlet NOx Emissions, lb/MMBtu
Percent reduction is related to the uncontrolled NOx level. Figure 2 shows the level of NOx reduction for various NOxlevels for coal-fired electric generating units (EGUs) . The best fit equation on the figure is used to estimate the level of reduction possible for the four BART EGUs . Equation 1 and Figure 3 are taken from the 2002 CCM and are recommended for estimating SNCR reagent usage . Equation 1 characterizes the lines on Figure 3. Equation 1 is used to estimate treatment rate for SNCR systems. Equation 1. Formula for estimating SNCR treatment rate 14 

### .VSR 

# = [2

### NO r 

## + 0

### .7 ] 

### 11 ,,o ! ~ ' x

13 Chapter 1 , Selective Noncatalytic Reduction , -6/5/2015 - Draft fo r Public Comment 14 US EPA, Air Pollution Control Cost Manual , EPA/452/8-02-001 , 2002 , Section 4.2, Page 1 -25 

### www.AndoverTechnology.comFigure 3. 

### Estimates of SNCR treatment rate as a function of inlet N0/ 5 3.0 -..----,--,---,----,---,---,----,r----,---r--r----,---r--r--....,...-""T"'I" ___ _ NOx Reduction 

### 2.8 

# I 

# ::\ JI~---------• --- ----- --**~**

# ~-::: 2.2 

# ',.\1 I - •

- 35% 

### ' , l\. I 

## \ \ 1, I 

### o: 2.0 -t-'-~ -'\ l --+---t---1----t---+--+--t----+---+--+-----<---+---+t

# ~ 

# \\ I', 

# l -o 

### 1.8 +-"--->-\l. +--~, ..,_..." __,__--+---+---+----<.----+---+--+-----<.----+---+--+----+-t

### ~ 

# \ I \. , ,**~** 

### ~~ Ir ~-

### ~ 1 .6 \ 

### · i \ ... • ............_ 

# I 

# a: 1.4 

# -~--1"' 1' " :.....~ .. ---. -

~:--...._~~ - :---_,,,,,,,_,....,_........-------............._ .._ .............-.......... _ .._,,............................. . I 1 , ,_ • • 

### 12 . r I '- •• - 50%

----- 30%

---- 25%

50% · .... 1 }............ "' • - -- _ • • • • 1,· 

## I \. I ...... i- -- • • • • •••• I ' • I- ' - - - - • • 

### t • • i • • 45% 1.0 . • , 1 "--. • - i- -**~** -i- ' 

## I ".... .... ...._....__ •**~** 

## .. - • _ • - - ...,...-**~** 

## - 40% i--- 1---._
- •**~** - ,..._ - ! 

### I

- I -- 

## I-•-·-·-· ~% 0 .8 30%



## ----- - - ---- ~ ! I 

### o.6 +-- !---+--+--+----<1---+--+--+----<1---+--+--+-"''-=-'l~~~ ..........~~~ 1 ~-=-1: 

### 1 =-=-==-i25% 

# I 0 .4 -1--;.-....,;.----+--;.--+---+--+---;.--+---+--+-----+------------1 0 .2 0 .3 0.4 0.5 0 .6 0 .7 0 .8 0.9 1 .0 1 . 1 1 .2 1 .3 1.4 1 .5 1 .6 1 .7 1.8 1 .9 2 .0 Uncontrolled NOx, lb/MMBtu 

### Other elements of SNCR variable operating cost and fixed operating cost are estimated using IPM algorithms that were developed for EPA by Sargent & 

### Lundy 16 

### (which happen to be consistent with Equation 1 .21 on page 1-33 in Chapter 1 Section 4.2 of the 2002 CCM). PacifiCorp indicated fixed operating costs rang ing from $277,500 to $280,000 per unit per year (or about $0.62/kW-yr), which is well above what is estimated methods consistent with the 2002 CCM (about $0.30/kW-yr). Without better explanation of these costs, the fixed operating cost of about $0.30/kW-yr determined using the methodology of the 2002 CCM is used.

15 Ibid 16 Sarge nt & Lundy, IPM Model - Updates to Cost and Performance for APC Technolog ies SNCR Cost Deve lopment Methodology Final Ma rch 2013 Project 12847-002 

### www.AndoverTechnology.comSCR 

### SCR capital cost is estimated using data provided by PacifiCorp . 17 

### PacifiCorp applied some of the factors and format of the 2002 CCM. However, the costs provided by PacifiCorp were adjusted here to account for items that are double-counted or should not be allowed under the CCM, such as AFUDC. PacifiCorp provided multiple capital cost estimates in PacifiCorp's BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, dated August 5, 2014, that included some duplication of costs that are identified in the spreadsheets attached with this report. In all cases some costs were accepted and others were not. The following are specific costs that were not accepted for any of these cost estimates. 1. Process Contingency 

### PacifiCorp provided cost estimates that follow the general format of the 2002 CCM. Although the 2002 CCM shows a process contingency of 5% in Table 2.5 in Section 4.2 (page 2-44), this is not necessary today for SCR on coal-fired boilers firing the coals used in Utah. The American Association of Cost Engineers (AACE) cost guidelines that the 2002 CCM is based upon allow for process contingency for commercially offered technologies to be in the range of 0% to 10%. 18• 19 

### Five percent, as indicated in the 2002 CCM, is the midpoint of this range . According to AACE 16R-90, 20 

### "The process contingency factor is applied in an effort to quantify the uncertainty in the technical performance due to limited design data."

The design data for these existing units - gas flowrates and concentrations, em ission requirements, coal to be used, and other characteristics are well known at this point. Therefore , data limitations on design data really do not exist. Further, According to the Department of Energy's National Energy Technology Laboratory, 21 

### "Process contingency is intended to compensate for uncertainty in cost estimates caused by performance uncertainties associated with the development status of a technology. Process contingencies are applied to each plant section based on its current technology status. " As noted in ATP's 2015 report,22 

### use of SCR today is extremely mature -far more mature than it was in 2002 when the CCM was issued . Figure 4 shows the cumulative installed capacity of coal fired

17 PacifiCorp' s BART Ana lys is Update for Hunter Units 1 and 2 and Hunti ngton Units 1 and 2, Aug ust 5, 20 14 18 AACE International Recommended Practice No . 16R-90, CONDUCTING TECHNICAL AND ECONOMIC EVALUATIONS-AS APPLIED FOR THE PROCESS AND UTILITY INDUSTRIES 19 US Department of Energy, Nationa l Energy Technology Laboratory, " Quality Guidelines fo r Energy Syste m Stud ies, Cost Esti mation Methodology fo r NETL Assessments of Powe r Plant Performance", DOE/NETL-2011/1455 20 AACE International Recommended Practice No . 16R-90 CONDUCTING TECHNICAL AND ECONOMIC EVALUATIONS-AS APPLIED FOR THE PROCESS AND UTILITY I NDUSTRIES 21 US Department of Energy, National Energy Technology Laboratory, " Quality Guidel i nes for Energy System Studies, -Cost Esti mating Methodology for NETL Assessments of Power Pl ant Performance", DOE/NETL-2011/1455, April 2011 , pg 4 . 22 Andove r Technology Partners, " Cost of NOx BART Controls on Utah EGUs" , October 22, 2015, pp 7-8 

### www.AndoverTechnology.com

### utility boilers equipped with SCR systems .23 

### As shown, the installed capacity of SCR on coal power plants is today about ten times what it was when the 2002 CCM was issued. As such there was very little experience with SCR on coal fired boilers in the US at the time of the 2002 CCM. Today, there is much more experience with many facilities having over a decade of operating experience. Figure 4 . 

### Coal fired utility boiler capacity with SCR (from Cichanowicz, 2013) 1 60,000 140,000 120.000 100,000

80,000 60,000 40 ,000 20 .000 0 2002 2003 20 2005 2006 2007 2008 200 2010 2011 2012 1013 20 14 20 1 5 

### Thus, the status of SCR technology in the United States today is very mature. Catalyst suppliers also supply catalyst on a global basis and are familiar with the effects of a wide range of coals with a wide range of materials that deactivate the catalyst. Therefore, the uncertainty in the performance of the SCR system at this point is much lower than it was in 2002, and the Process Contingency should therefore be significantly reduced from what it was in 2002. The primary concern that relates to performance uncertainty is with regard to how quickly the catalyst will deactivate . The deactivation rate impacts how much catalyst must be initially installed to achieve adequate performance at a point in the future . Catalyst deactivation is primarily impacted by the various deactivating species that may be present in the coal. ATP examined and compared the concentrations of species that deactivate the catalyst for the Utah coals in question against concentrations for US coals that are very well known (see ATP 2015 report page 12) and concluded that the Utah coals had qualities that were favorable when compared to these other coals .

23 Cichanowicz , J. E., " CURRENT CAPITAL COST AND COST-EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL TECHNOLOGIES" , Prepared for Utility Air Regulatory Group , January 2013 

### www.AndoverTechnology.comAs part of PacifiCorp's comments, Sargent & Lundy raised the concern about phosphorus deactivation that has been experienced for some plants firing Powder River Basin {PRB) coals (S&L, page 6 of Attachment 5 of PacifiCorp comments), but did not examine the phosphorus content of the Utah coals. Examination of USGS coal quality database 24 data shows phosphorus in the ash in Utah coals to be lower than for PRB coals, especially when compared on a heating value basis . Even so, mitigation methods that are effective at addressing this issue should they be necessary are available .25 The mitigation method entails addition of iron-bearing material to the fuel that will convert gaseous phosphorus to particle phosphorus and thereby avo id the catalyst deactivation from gaseous phosphorus. 26 Ifthis additive were necessary (and, it may not be), it would entail addition of material onto the coal. The equipment would amount to nothing more than a storage silo and pneumatic or other device to put the material onto the coal while it is being transported on the coal belt. 27• 28 The cost of such equipment, if needed, is minimal, and would be well below the 5% Process Contingency that PacifiCorp believes may potentially be necessary to address this . This decision to disallow Process Contingency is also consistent with a previous EPA determination regarding use of Process Contingency in BART cost estimates for SCR . 29 

### 2. Project Contingency of15% is too high in light ofthe cost method used and very conservative underlying assumptions. PacifiCorp's estimates are based upon detailed estimates of the labor and materials to build the SCR . As a result, a 15% project contingency is excessive. According to AACE 16R-90 on page 15: "Project Contingency is included to cover the costs that would result if a detailed-type costing was followed as in a definitive-type study. For a budget-type estimate, project contingency would range from 15% to 30%." According to NETL, 30 "AACE 16R-90 states that project contingency for a "budget-type" estimate (AACE Class 4 or 5) should be 15% to 30% of the sum of BEC, EPC fees and process contingency ." When using the 2002 CCM methodology the direct capital costs and other associated costs are developed only from facility and SCR performance characteristics, such as boiler flow, NO. levels, NO.

24 http ://ncrdspublic.er.usgs.gov/coa Iqua I/ 25 M Gadgil, "Deactivation of Selective Catalytic Reduction (SCR) Catalyst by Phosphorus: Proposed Mechanism and Solution, " Presented at the International Pittsburgh Coal Conference, September 12-15, 2011. M Gadg i l et al , "Combustion Additives for Control of Phosphorus Effects and Achieving Mercury Reduction ," Presented at Power-Gen Europe, June 3 - 5, 2014 . 26 US Patents 8303919 82 , 8691719 , and 8716169. 27 Telephone conversation Mandar Gadgil 3/18/16 28 Gadgil, M ., Pierson , L., Hansen, E., Silbaugh, D., Meier, J., "Improvement in Performance of SCR Catalyst Usi ng Combustion Add itives : Technology Status Update, 2012 Mega Symposium , Paper and Presentation #2 29 Federal Register/ Vol. 79, No . 20 

### I Thursday, January 30, 2014 

### I Rules and Regulations , pp 5140, 5150 30US Department of Energy, National Energy Technology Laboratory, " Quality Guidelines for Energy System Studies, -Cost Estimating Methodology for NETL Assessments of Power Plant Performance", DOE/NETL-2011/1455, April 201 , pg 5. www.AndoverTechnology.com

### reduction, etc. The 2002 CCM therefore uses a parametric method for determining cost. The direct capital costs are determined using Equation 2.36 on page 2-42 of Section 4.2 Chapter 2 of the 2002 CCM and factors are applied to determine other costs, such as project contingency. The cost estimating methodology described in the 2002 CCM does not entail estimates of labor hours for specific tasks, quantities of material for specific parts of the system, etc. For the methodology described in the 2002 CCM a project contingency of 15% is recommended . Therefore, the more detailed and complete the estimate, the lower the project contingency should be . Furthermore, the 2002 CCM states at Section 1.1 Chapter 1, page 1-4, "The accuracy of the information in the Manual works at two distinct levels. From a regulatory standpoint, the Manual estimating procedure rests on the notion of the "study" (or rough order of magnitude - ROM) estimate, nominally accurate to within± 30%. This type of estimate is well suited to estimating control system costs intended for use in regulatory development because they do not require detailed site-specific information necessary for industry level analyses." Also, on Section 1.1 Chapter 2, page 2-3 it states:

"As mentioned in Chapter 1 . 1, the costs and estimating methodology in this Manual are di rected toward the " study" estimate with a nominal accu racy of± 30% percent . According to Perry' s Chemical Engineer's Handbook, a study estimate is " ... used to estimate the economic feas ibil ity of a project before expending sign ificant funds for piloting, marketing, land surveys, and acquisition ... [However] it can be prepared at relatively low cost with minimum data ." Therefore, it is clear that the methodology described in the 2002 CCM entails a study using fairly little input data and at a low cost. By contrast, the cost estimate developed for PacifiCorp includes project definition down to details of how much of each type of material (to include details of indirect costs, such as quantity of handrails, cubic yards of material , SCR reactor doors, how many parking signs are needed, guard posts in the parking area, and square feet of road repair) . Most certainly, the methodology outl ined in the 2002 CCM did not envision a cost estimate with the level of detail included in the estimate developed by Sargent & 

### Lundy in PacifiCorp's BART analysis . AACE provides the classifications shown in Table 1. 3 1

31 AACE International Recommended Practice No . 18R-97, COST ESTIMATE CLASSIFICATION SYSTEM -AS APPLIED IN ENGINEERING, PROCUREMENT, AND CONSTRUCTION FOR THE PROCESS INDUSTRIES 

### www.AndoverTechnology.comTable 1. Classifications of Cost Estimates32 Primary C/Jaracteristic Secondaty Characteri5tic M ATU RITY LEVEL OF PROJE C T DEFIN ITI ON EN D USAGE E XPE CTED ACCURACY ESTIMATE METHODOLOGY RANGE

CL

ASS DELIVER ABLES T ypical purpose of Typical estimating method Typ1cal variati on in low and high Expressed as % ofcompl ete estimate ranges rt! de inhion Concept Capaci ty factored, L: -20% to -50% Class S O%to 2% parametric mode.ls, screen in g j udgment, or analogy H: +30% o+l00% 1 %to 15% S udy or Equ ipment factored or L: ·15%to -30% Class 4 feasib i l ity parametric models H: +20%to +50% Budget Semi-detailed unit costs -10% to -20% l.: Class 3 10 %to40% authorization or with assembly level line H: +10% to +30% control items Class 2 30%to 75% Control or Detailed unit cost with L: -5% to ·15% bid/tende forced detailed take-off H: +5% to +20% Class 1 65%to 100% Check estimate Detailed unit cost with L: ·3% to ·10% or bid/tender detailed take-off 

### H: +3% to +15% Notes: { aj The state of process technol ogy, availability of appl icable reference cost data, and many other risks affea th e range markedlv. The +f· value represents t~'l)ical percentage variation of aaual costs from the cost estimate after app lication of contmgen<y (typi cally at a SO'!". l evel of confidence) for given <;cope . The two important columns to look at are the "Primary Characteristic" or "Maturity Level of Project Definition Deliverables" and "Methodology". The "Project Definition Deliverables" should not be confused with the percent of total project engineering, as Sargent & Lundy appears to have done in their comments .33 Project Definition Deliverables is the degree to which the project has been defined, and the level of detail to which it is defined. The completeness is determined by how much detail is included in the estimate . The methodology used for Class 4 and Class 5 estimates are clearly indicated as parametric or factored models, such as described in the 

### 2002 CCM (PacifiCorp has not disputed that the method as described in the 

### 2002 CCM is Class 

### 4 or 

### 5) or, for example, in US EPA's Coal Utility Environmental Cost (CUECOST) Model. Table 

### 2 shows an example of an estimate from the 

### 2000 version of CUECOST, called CUECOST3. 34 CUECOST3 only estimates the costs for the major project areas, such as reactor housing and installation, ammonia handling system, etc. based upon process inputs such as boiler gas flowrate, NOxlevel, percent reduction, retrofit difficulty factor, etc. In the case of CUECOST3 20% contingency is provided for (15% project and 5% process) because the completeness of the project definition deliverables is limited only to estimates of major system areas, and a significant portion of the costs would likely be overlooked without the contingency.

32 AACE International Recommended Practice No. 18R· 97, COST ESTIMATE CLASSIFICATION SYSTEM -AS APPLIED IN ENGINEERING , PROCUREMENT, AND CONSTRUCTION FOR THE PROCESS INDU5TRIE 33 S&L comments, Attachment 5 to PacifiCorp comments, pages 7-9 . 34 US EPA Coal Utility Environmental Cost Model , Download at : https ://www3.epa.gov/ttncatcl/products . html www.AndoverTechnology.comTable 2. 

### Example of capital cost estimate developed using CUECOST3 SCR Capital Costs 

### easel Cost Basis (Year) 

### 1998 Reactor Housing and Installation $ 4,055,272 Ammonia Handling and Injection $ 1,917,147 Flue Gas Handling : Ductwork and Fans $ 5,112,798 Air Preheater Modifications $ 1,271,466 Misc. Other Direct Capital Costs $ 416,262 Equipment Capital Cost Subtotal $ $12,772,945 Instruments & 

### Controls $ $255,459 Taxes $ $766,377 Freight $ $638,647 Total Direct Cost 

### $14,433,428 Total Direct Cost with Retrofit Factor 

### $ $18,763,456 General Facilities $ $938,173 Engineering Fees $ $1,876,346 Contingency $ $3,752,691 Total Plant Cost (TPC} 

### $ $25,330,666 Total Plant Cost (TPC) w/Prime Contractor's 

### $ $26,090,586 Total Cash Expended (TCE) 

### $ $25,338,043 Allow. for Funds During Constr. {AFDC} 

### $ $2,778,208 Total Plant Investment (TPI} 

### $ $28,116,252 Preproduction Costs $ $722,219 Inventory Capital InitialAmmonia(60 days) $ $151,522 Initial Catalyst $ $8,788,650 Total Capital Requirement (TCR) 

### $ 

### $37,778,643 $/kW $76 By contrast, the estimate made by Sargent & 

### Lundy for PacifiCorp does not use the parametric methodology described in Table 3 for Class 4 or 5 cost estimates. Moreover, the completeness of the Project Definition Deliverables in Sargent & 

### Lundy's estimate is very thorough, and goes to a much greater level of detail than envisioned for a Class 4 or 5 estimate. Therefore, the methodology used in the CCM falls into a Class 4 or Class 5, while the methodology used by PacifiCorp in their BART analysis35 

### is clearly a far more detailed estimate that leaves out very little, if any, project definition. As a result, the cost estimate provided by PacifiCorp, with hundreds of line items for each SCR, each with estimated material quantity, material cost, labor quantity and labor cost - essentially, thousands of pieces of input data regarding cost and quantities of material - is a far more mature estimate with much greater project definition than envisioned in the

35 PacifiCorp' s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014 

### www.AndoverTechnology.com

### 2002 CCM. In effect, PacifiCorp appears to be trying to combine an estimate with a very comprehensive definition of Project Deliverables while also using a project contingency intended for an estimate with much less complete definition of Project Deliverables. In light of the comprehensive list of project deliverables in the cost estimate made by Sargent 

### & Lundy for PacifiCorp, the Project Contingency of 15% indicated for the method described in the 2002 CCM is far too high and is not allowed. This determination is also consistent with a previous EPA determination regarding Project Contingency. 36 

### 3. General Facilities As described in AACE 16R-90: "General Facilities: These include roads, fences, shops, laboratories, office buildings, etc., and are generally in the range of 5% to 20% of Total Process Capital" According to the 2002 CCM, for the methodology described in the 2002 CCM a value of 5% of Total Direct Costs is recommended. 37 

### No other line item costs for General Facilities are included in the 2002 CCM. The cost estimate for PacifiCorp on all four units included a number of items that would fall into the category of General Facilities, and in order to avoid double-counting, an additional line item for General Facilities will not be included. To 

### be more specific, examining PacifiCorp's BART Analysis Update for Hunter Units 1 and 2 and Huntington Un its 1 and 2 from August 5, 2014, numerous items are included under the categories of Civil Work and Architectural that would fall into the category of General Facilities, such as roadways, road signs, eyewash stations, pre-fabricated buildings, fire protection, and other items, examples as shown In Figure 5. In addition, in line item 27 .00 .00 of the cost estimate38 

### Sargent & Lundy included the cost to coat or paint these architectural items. All of these items clearly fall under the category of General Facilities items, including the eyewash stations that Sargent 

### & Lundy identifies under the category Architectural as opposed to process equipment or any other category. Adding an additional 5% for General Facilities would be double counting.

36 Federal Register 

### I Vo l. 79 , No. 20 

### I Thursday, January 30, 2014 

### I Rules and Regulations, pp 5140, 5151 37 2002 CCM , page 2-42 of Section 4 .2 Chapter 2 page 2-44 38 PacifiCo rp' s BART Analysis Update for Hunter Un its 1 and 2 and Huntington Units 1 and 2, August 5, 2014, Pdf pp 54, 65, 89 , 100 

### www.AndoverTechnology.com

### ~ig~r~ - ~· ~~n~r~I._Fa

_ c JH~~s

_ items in the detailed Conceptual Cost estimate. 21 .41 .15 Crushed Rock Surfacina I 1 21.57.15 BitumiOOU'i Ro:ad Bnumioous Road O'f\UUl:U-tUU!lt nua:u I 21 .57.85 Road & Parkina S111n i'road S. '-'a.t!l"l'.l Skin 'pa,'e!T'l!:!'ltrnlilllnq 1.000.00 Lf



# -**~** & ?.nlrf.l Sl:in GJa:t! oos?.s. tc0aete 11uea Road 8. Pait!M Sl!ln i~ill"$

Road & Park.inn Sron 

### CI

VIL WORK



# - ....,.

# __ ._

----- -·---------'"<ffNHC~""-='" __ ,, ___ ,_,m___ ,,_ -----·- 2.

4.00.00 ARCH JTECTURAl ,.JG alH lt'o•i'Zef

AH C HITECT U RAL 31 41 .9~ Fire Prote<:tion Eauit'lffle-nt. & Svstem. lJse.r DefiM<i Ifine 'Pl'!l(ecilcn Eqtt~ !. ~m IFire WJ:'O{M..sloo sy~,;m or UAT f.rallstOim!ffi ISl.l!l«#ltrao:) Fire Prot~ion EQu:ir:mWcnt & Svstem, User Defined 15. 00 EA 1.00 IS

135,000 135,000
2:00 LS



### Like Project Contingency, PacifiCorp appears to be using a General Facilities cost factor that was intended for a cost estimate as described in the 2002 CCM that is far less complete in terms of the definition of project deliverables. Therefore, the 5% General Facilities factor indicated in the 2002 CCM for the methodology described in the 2002 CCM is not allowed in combination with the estimate provided by PacifiCorp. This is also consistent with a previous EPA determination regarding General Facilities costs. 39 4. AFUDC 

### AFUDC is not included in the cost methodology of the 2002 CCM and therefore was not allowed. PacifiCorp correctly excluded this from their estimate .

39 Fede ral Reg ister 

### I Vol. 79 , No. 20 

### I Thursday, January 30 , 2014 

### I Rules and Regulations, pp 5141 , 5149 

### www.AndoverTechnology.com

### 5. Sales Taxes Sales taxes from the PacifiCorp cost estimate are excluded, as these do not apply to environmental upgrades in Utah .40



### 6. Property Tax A line item for capitalized property tax is shown for each of the SCR cost estimates in the 2014 cost estimate for PacifiCorp . An annualized property tax factor is also applied. 4 1 This is incorrect treatment of property taxes and essentially double counts property taxes. A tax rate of 1.0%, consistent with PacifiCorp's 2014 submittals (page 25) is assumed, along with a declining apportionment of value, per Utah's Recommended Personal Property Valuation Schedules .42 The payment equivalent of the net present value of this payment streams is used to determine the annual equivalent payment per Equation 2.7 of Section 1 of the 2002 CCM. The Class 8, Machinery and Equipment schedule, from the 2015 Recommended Personal Property Valuation Schedules and Registered Vehicle Uniform Fees, Utah State Tax Commission, Property Tax Division was used . Using the 1% base tax rate, this provides a schedule of declining valuations, starting at 93% of acquisition cost in year one (first full year of ownership) to 11% of acquisition cost in year 11 and zero in year 12 . In effect, the tax rate in year one is 0.93% of acquisition cost and declines steadily to zero in year 12 . This payment stream was then annualized to develop an equivalent annual payment using Equation 2.7 of Section 1 of the 2002 CCM (see worksheet Property taxes) to provide an annual cost that is used in the cost analysis of worksheet SCR_PacifiCorp_Annual_ Adjusted line 

### 106. Equation 2.7 of Section 1 of the 2002 CCM develops an annual payment equal to the present value of a future tax payment stream.
7. 

### Indirect Installation Costs According to the 2002 CCM, page 2-43,



### "Indirect installation costs are those associated with installing and erecting the control system equipment but do not contribute directly to the physical capital ofthe installation. This generally includes generalfacilities and engineering costs such as construction and contractorfees,

40 HEAL UTAH* NATIONAL PARKS CONSERVATION ASSOCIATION * SIERRA CLUB, Comments on Proposed Amendments to Utah's Regional Haze Rule, December 22, 2014 41 PacifiCorp's BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014, page 47 also see SCR_PacifiCorp_Annual_ Adjusted worksheet lines 28 and 106 42 Class 8, Machinery and Equipment schedule, from 2015 Recommended Personal Property Valuation Schedules and Registered Vehicle Uniform Fees, Utah State Tax Commission, Property Tax Divis ion www.AndoverTechnology.com

### preproduction costs such as startup and testing, inventory capital and anyprocess andproject contingency costs. " Per Table 2.5, on page 2-44 Section 4 .2 Chapter 2 ofthe 2002 CCM, indirect installation costs are General Facilities, Engineering 

### & Home Office Fees, and Process Contingency. Treatment of General Facilities and Process Contingency are discussed elsewhere in this report . For Engineering 

### & Home Office Fees the recommended 10% of Total Direct Costs per the 2002 CCM was applied (see line 38 of SCR PacifiCorp Annual Adjusted worksheet of UT EGU BART Costs workbook). Contractor Construction Management and Contractor Training Classes (see lines 31 and 33 of same worksheet) were excluded because they are included in the Engineering 

### & Home Office Fees. Therefore, 10% of Total Direct Costs is what is permissible under the 2002 CCM. 

### 8. Catalyst and Catalyst reactor and Induced Draft Fan The SCR reactor design, catalyst volume, catalyst replacement frequency, and the induced draft fan developed by PacifiCorp and Sargent 

### & Lundy have been accepted. Installed cost of catalyst, however, is assumed to be $5500 per cubic meter. Information on catalyst pricing was available in the publicly available documents relating to the Lakeland Macintosh 3 SCR catalyst layer replacement. These documents indicated that new catalyst prices had, in fact, dropped to around $3500/cubic meter or less. 43 Adding $1285 per cubic meter for installation per Sargent 

### & Lundy's estimate results in a cost of under $5000 per cubic meter. The existing layers were 5380 cubic feet, or about 152 cubic meters each. 44 In the case of Lakeland Macintosh 3, they decided to regenerate two layers of catalyst for a price of $501,66045 rather than purchase new catalyst. This equates to roughly $1650 per cubic meter. Therefore, for EPA's BART analysis, an installed price of $5500 per cubic meter for catalyst is conservatively high and will continue to be assumed for both initial installation and replacement catalyst, and this is consistent with a previous EPA determination .46

43 NOTICE TO BIDDERS, INVITATION TO BID UNIT 3 SCR CATALYST LAYER REPLACEMENT, At the, MCINTOSH POWER PLANT, September 1 , 2015, BID NO . 5266A (pdf pages 19 and 46 show 2 SCR reactors pdf page 49 for number of modules per reactor and di mensions of modules . 90 modules, assuming typical modu le cross sect ion of 1.8 m2 and depth of 1.14 m and CERAM price $570,000 results in $3100/m3 . BID TABULATION , CITY OF LAKELAND FLORIDA, PURCHASING AND STORES DIVISION , 1140 E PAR KER STREET, LAKELAND , FL. 33801, Bid Number: 5266A, Title : Unit 3 SCR Catalyst Layer Replacement, Date : 9/23/2015 Memorandum , To Mayo r and City Commission , From City Attorney's Office, Re : Approval to Procure Services with SCR-Tech to Regenerate Catalys t Laye rs for Mcintosh Power Plant Unit 3 Selective Catalytic Redu ct ion Reactor System , January 4, 2016 44 Memo rand u m, To Mayor and City Commission , From City Attorney' s Office , Re: Approval to Procure Services with SCR-Tech to Regene rate Catalyst Layers for Mcintosh Power Plant Unit 3 Selective Catalytic Reduction Reactor System , January 4, 2016, p 55 45 Ibid, pp 2, 81 46 Federal Reg ister 

### I Vol. 79 , No . 20 

### I Thursday, January 30, 2014 

### I Rules and Regulations , pg 5143 www.AndoverTechnology.com

### 9. Operating Cost
- Cost ofgenerating steamfor hydrolyser On page 47 of their August 2014 submittal PacifiCorp uses a cost of fuel of $5/MMBtu to generate steam. This is incorrect. The urea hydrolyser will utilize steam from the boiler, the cost of which is the additional fuel needed to generate the steam. According to FERC Form 1 data, the cost of fuel at the plants is as shown in Table 3. PacifiCorp' s cost of ene rgy to heat the steam was therefore changed to these values and adjusted for actual capacity factor . Table 3. Reported Fuel Cost in 2014 FERC Form 1 Plant unit Average Fuel Cost, $/MMBtu Hunter 1 1.9590 Hunter 2 1. 9080 Huntington 1 1 .8300 Huntington 2 1 .8300



### www.AndoverTechnology.comAssumptions 

### In estimating cost of control, it is assumed that a full complement of combustion controls, including new Low NOx Burner Technology w/ Separated OFA, are implemented prior to installation of post-combustion controls (SNCR and SCR) . Actual annual average emissions rates for the 2001-2003 period were used to estimate the emission rate prior to installation of new combustion controls. Similarly, actual annual average emissions rates for 2014 and the first two quarters of 2015 were used to estimate the emission rate following with new combustion controls . For 2014, full year data was used, except for Hunter 

### 1. In the case of Hunter 1, only 2014 May to December data was used because combustion controls were installed in April. The average reported emission rates for 2001-2003, 2014 and 2015 (quarters 1 & 

### 2) are shown in Table 4. These demonstrate that all four units installed combustion controls to reduce NOx emissions since 2003.
Table 4. Reported emission rates for affected EGUs Annual Avg. NOx Rate (lb/MMBtu) Facility Unit Heat Input, AVG 

### after Facility Name ID ID MMBtu 2001- 2015 

### avg comb 2014 

### (ORISPL) 2001-03 2003 Ql,Q2 

### controls avg. Hunter 6165 1 31,372,895 0.4006 0.209 0.204 

### 0.2067 Hunter 6165 2 31,537,898 0.3817 0. 195 0.201 

### 0. 1977 Huntington 8069 1 31,365,923 0 .3747 0 .214 0.224 

### 0.2191 Huntington 8069 2 29,899,997 0 .3860 0.224 0.203 

### 0 .2136 All histo rica l em issions and heat input data were developed from the EPA Air Ma rkets Program Data. Hunter 1 2014 data was May to December because of combustion control installation in April , other units were the complete year



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# 3. Estimated Costs The capital cost estimates are reflective of 2014 dollars with capital costs all adjusted to 2014 using the CEPCI. The cost calculation results are summarized in the following sections of this report and are detailed in the Microsoft Excel workbooks attached to this report:

• Microsoft Excel Workbook UT EGU BART_ Costs_2016_RTC_20 year.xlsx, and • Microsoft Excel Workbook UT EGU BART _ Costs

_2016_RTC_30 year.xlsx The details of the estimating methods are described in the workbooks . Consistent with the EPA Control Cost Manual, 47 capital cost estimates do not include AFUDC or Owner' s Costs (beyond the 10% allowed for engineering and home office) . For combustion controls, capital and operating costs are based upon what was provided by PacifiCorp. 7 For consumables, the following estimates are used: • Urea - delivered price of urea prill about $489/ton 48 • Power and fuel - based upon 2014 FERC Form 1 data Although anhydrous ammonia is generally a less expensive SCR reagent, urea has advantages especially with regard to safety. Since PacifiCorp has indicated urea as the SCR reagent in its cost estimate to include a urea to ammonia system with solutionizing equipment, 49 it is assumed that urea prill will be the reagent of choice, with the understanding that if PacifiCorp were to later select anhydrous ammonia, the capital and operating costs would both be somewhat lower. Capital costs for the combustion controls were determined from PacifiCorp's estimates, and ranged from about $17/kW to $26/kW. The capital costs estimated for the SNCRs range from $16/kW to $17/kW . The capital costs estimated for the SCRs range from $261/kW to $278/kW .

47 EPA. 2002 . EPA Air Pollution Contro l Cost Manual (Sixth Edition) . EPA/452/8-02-001 , p 2-5 - 2-7 489/23/15 email Fuel Tech 49 PacifiCorp' s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014, pp 74, 108 

### www.AndoverTechnology.com

### Hunter 1 

### & 2 An overhead view of Hunter plant is shown in Figure 6. Hunter units 1 and 2 are the two units to the left. Units 1 and 2 are tangentially fired units that have recently added more modern combustion controls . Figure 6. Hunter Power Plant

It was previously determined that post-combustion NO. 

### controls, including SNCR 

### and SCR, 

### are feasible .50 

### Detailed cost estimate calculations are provided in the Microsoft Excel workbook provided with this report . Tables Sa through Sd show the estimated costs of control for each of the Hunter units using 20 year or 30 year lifetimes. Although the units are similar, costs will vary somewhat for each unit due to: 1 ) different installed costs for equipment that are determined by unit specifics, and; 2) somewhat different actual emission rates for each unit.

so PacifiCo rp's BART Analys is Update for Hunter Un its 1 and 2 and Hunti ngton Un its 1 and 2, August 5, 2014 

### www.AndoverTechnology.comTable Sa . Hunter 1 estimated costs (20 year life) Comb Control (CC) SNCR SCR CC and SNCR CC and SCR Capital Cost, $/kW $26 $17 $267 $43 $293 Control Efficiency 48% 21% 76% 59% 88% Uncontrolled Rate NOx Rate (lb/hr) 1922 992 992 1922 1922 NOx Rate (lb/MMBtu) 0.40 0 .21 0.21 0.40 0.40 NOx (TPY) 6284 3242 3242 6284 6284 Controlled Rate NOx Rate (lb/hr) 992 780 240 779.81 239 .95 NOx Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05 NOx (TPY) 3242 2549 784 2548.98 784.32 Tons/Year Removed 3042 693 2458 3735 .01 5499.67 Total Cost/year $1,161,898 $2,632,634 $13,670,265 $3,794,531 $14,832,163 $/Ton $382 $3,796 $5,561 $1,016 $2, 697 $/ton Incremental $3,796 $6,255 $3,796 $6,255 incremental incremental incremental incremental

versus CC versus SNCR versus CC versus CC and SNCR Table Sb. Hunter 2 estimated costs (20 year life) Comb Control (CC) SNCR SCR CC and SNCR CC and SCR Capital Cost, $/kW $20 $18 $279 $38 $299 Control Efficiency 48% 21% 75% 59% 87% Uncontrolled Rate NOx Rate (lb/hr) 1,765 914 914 1,765 1 , 765 NOx Rate (lb/MMBtu) 0.38 0 .20 0.20 0 .38 0.38 NOx (TPY) 6,018 3,117 3,117 6,018 6,018 Controlled Rate NOx Rate (lb/hr) 914 720 231 720 231 NOx Rate (lb/MMBtu) 0.20 0.16 0.05 0.1 6 0 .05 NOx (TPY) 3,117 2,457 788 2,457 788 Tons/Year Removed 2,902 660 2,328 3,562 5,230 Total Cost/year $864,040 $2,583,159 $13, 645,778 $3,447,199 $14,509,819 $/Ton $298 $3,913 $5,861 $968 $2,774 $/ton Incremental $3,913 $6,632 $3,913 $6,632 incremental incremental incremental incremental

versus CC versus SNCR versus CC versus CC and SNCR



### www.AndoverTechnology.comTable Sc. Hunter 1 estimated costs (30 year life) Comb Control (CC) SNCR SCR CC and SNCR CC and SCR Capital Cost, $/kW $26 $17 $267 $43 $293 Control Efficiency 48% 21% 76% 59% 88% Uncontrolled Rate NOx Rate (lb/hr) 1922 992 992 1922 1922 NOx Rate (lb/MM Btu) 0.40 0.21 0.21 0.40 0.40 NOx (TPY) 6284 3242 3242 6284 6284 Controlled Rate NOx Rate (lb/hr) 992 780 240 779.81 239 .95 NOx Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05 NOx (TPY) 3242 2549 784 2548.98 784.32 Tons/Year Removed 3042 693 2458 3735.01 5499.67 Total Cost/year $1,001,925 $2,530,041 $12,026,858 $3,531,966 $13,028,783 $/Ton $329 $3,648 $4,893 $946 $2,369 $/ton Incremental $3,648 $5,382 $3,648 $5,382 incremental incremental incremental incremental

versus CC versus SNCR versus CC versus CC and SNCR Table Sd. Hunter 2 estimated costs (30 year life) Comb Control (CC) SNCR SCR CC and SNCR CC and SCR Capital Cost, $/kW $20 $18 $279 $38 $299 Control Efficiency 48% 21% 75% 59% 87% Uncontrolled Rate NOx Rate (lb/hr) 1,765 914 914 1,765 1,765 NOx Rate (lb/MM Btu) 0.38 0 .20 0.20 0.38 0.38 NOx (TPY) 6,018 3,117 3,117 6,018 6,018 Controlled Rate NOx Rate (lb/hr) 914 720 231 720 231 NOx Rate (lb/MMBtu) 0.20 0.16 0.05 0. 16 0.05 NOx (TPY) 3,117 2,457 788 2,457 788 Tons/Year Removed 2,902 660 2,328 3,562 5,230 Total Cost/year $745,077 $2,481,625 $11,990,664 $3,226,702 $12,735,741 $/Ton $257 $3,759 $5,150 $906 $2,435 $/ton Incremental $3,759 $5,701 $3,759 $5,701 incremental incremental incremental incremental versus CC and versus CC versus SNCR versus CC SNCR



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### Huntington 1 & 2 An overhead view of Huntington plant is shown in Figure 7. Units 1 and 2 are tangentially fired units and have recently added more modern combustion controls . Units 

### 1 and 

### 2 are tangentially fired units that have recently added more modern combustion controls. Figure 

### 7. Huntington Power Plant

It was previously determined that post-combustion NOx

### controls, including SNCR 

### and SCR, 

### are feasible. 51 

### Detailed cost estimate calculations are provided in the Microsoft Excel workbook provided with this report. Tables 6a through 6d show the estimated costs of control for each of the Huntington units using 

### 20 year or 

### 30 year lifetimes. Although the units are similar, costs will vary somewhat for each unit due to : 1) different installed costs for equipment that are determined by unit specifics, and; 2) somewhat different actual emission rates for each unit.

51 PacifiCorp' s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, Augu s t 5, 2014 

### www.AndoverTechnology.comTable 6a. 

### Huntington 1 estimated costs (20 year life) Comb Control (CC) SNCR SCR CC and SNCR CC and SCR 

### Capital Cost, $/kW $18 $17 $261 $34 $278 

### Control Efficiency 42% 22% 77% 54% 87% Uncontrolled Rate NOx 

### Rate (lb/hr) 1741 1018 1018 1741 1741 NOx 

### Rate (lb/MMBtu) 0.37 0.22 0.22 0.37 0.37 NOx 

### (TPY) 5876 3436 3436 5876 5876 Controlled Rate NOx 

### Rate (lb/hr) 1018 797 232 797 232 NOx 

### Rate (lb/MMBtu) 0.22 0.17 0.05 0.17 0.05 NOx 

### (TPY) 3436 2692 784 2,692 784 

### Tons/Year Removed 2440 745 2652 3,185 5,092 

### Total Cost/year $810,754 $2,686,934 $13,808,205 $3,497,687 $14,618,959 

### $/Ton $332 $3,609 $5,206 $1,098 $2,871 

### $/ton Incremental $3,609 $5,830 $3,609 $5,830 incremental incremental incremental incremental

versus CC versus SNCR versus CC versus CC and SNCR Table 6b. 

### Huntington 2 estimated costs (20 year life)

Comb Control (CC) SNCR SCR CC and SNCR CC and SCR 

### Capital Cost, $/kW $21 $17 $268 $38 $289 

### Control Efficiency 45% 22% 77% 57% 87% Uncontrolled Rate NOx 

### Rate {lb/hr) 1,762 976 976 1,762 1,762 NOx 

### Rate (lb/MMBtu) 0.39 0.21 0.21 0.39 0.39 NOx 

### (TPY) 5,770 3,194 3,194 5,770 5,770 Controlled Rate NOx 

### Rate (lb/hr) 976 765 228 765 228 NOx 

### Rate (lb/MMBtu) 0.21 0.17 0.05 0.17 0.05 NOx 

### (TPY) 3,194 2,506 747 2,506 747 

### Tons/Year Removed 2,576 688 2,446 3,264 5,023 

### Total Cost/year $941,438 $2,566,724 $13,764,311 $3,508,162 $14,705,749 

### $/Ton $365 $3,730 $5,626 $1,075 $2,928 

### $/ton Incremental $3,730 $6,368 $3,730 $6,368 incremental incremental incremental incremental versus CC and versus CC versus SNCR versus CC SNCR



### www.AndoverTechnology.com

### Table Ge. Huntington 1 estimated costs (30 year life) Comb Control {CC) SNCR SCR CC and SNCR CC and SCR 

### Capital Cost, $/kW $18 $17 $261 $34 $278 

### Control Efficiency 42% 22% 77% 54% 87% 

### Uncontrolled Rate NOx 

### Rate (lb/hr) 1741 1018 1018 1741 1741 NOx 

### Rate (lb/MMBtu) 0.37 0.22 0.22 0.37 0.37 NOx 

### (TPY) 5876 3436 3436 5876 5876 

### Controlled Rate NOx 

### Rate (lb/hr) 1018 797 232 797 232 NOx 

### Rate (lb/MMBtu) 0.22 0.17 0.05 0.17 0.05 NOx 

### (TPY) 3436 2692 784 2,692 784 

### Tons/Year Removed 2440 745 2652 3,185 5,092 

### Total Cost/year $699,127 $2,584,341 $12,148,447 $3,283,468 $12,847,574 

### $/Ton $287 $3,471 $4,580 $1,031 $2,523 

### $/ton Incremental $3,471 $5,013 $3,471 $5,013 incremental incremental incremental incremental

versus CC versus SNCR versus CC versus CC and SNCR 

### Table Gd. Huntington 2 estimated costs (30 year life)

Comb Control {CC) SNCR SCR CC and SNCR CC and SCR 

### Capital Cost, $/kW $21 $17 $268 $38 $289 

### Control Efficiency 45% 22% 77% 57% 87% 

### Uncontrolled Rate NOx 

### Rate (lb/hr) 1,762 976 976 1,762 1,762 NOx 

### Rate (lb/MMBtu) 0.39 0.21 0.21 0.39 0.39 NOx 

### (TPY) 5,770 3,194 3,194 5,770 5,770 

### Controlled Rate NOx 

### Rate (lb/hr) 976 765 228 765 228 NOx 

### Rate (lb/MMBtu) 0.21 0.17 0.05 0.17 0.05 NOx 

### (TPY) 3,194 2,506 747 2,506 747 

### Tons/Year Removed 2,576 688 2,446 3,264 5,023 

### Total Cost/year $811,819 $2,465,190 $12,098,989 $3,277,009 $12,910,807 

### $/Ton $315 $3,583 $4,945 $1,004 $2,570 

### $/ton Incremental $3,583 $5,479 $3,583 $5,479 incremental incremental incremental incremental

versus CC versus SNCR versus CC versus CC and SNCR



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