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 

NOx Control 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 NOx controls 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 20141 

PacifiCorp Hunter Unit 2: Low NOx Burner Technology w/ Separated OFA; installed 20112 

PacifiCorp Huntington Unit 1: Low NOx Burner Technology w/ Separated OFA; installed 20113 

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 Manual6 

• 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 indicates 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 Analysis 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 Final March 2013 Project 12847-002 

Sa rgent & Lundy, IPM Model - Updates to Cost and Performance for APC Technologies SCR Cost Development Methodology 

Final 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 Utah8 

• 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 Data10 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 Unit 1, July 2, 2012 

PacifiCorp BART Analysis of Hunter Unit 2, June 7, 2012 

PacifiCorp BART Analysis of Huntington Unit 1, June 26, 2012 

PacifiCorp 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 Regional Haze Rule; 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 , line 35 

10 http://ampd .epa.gov/ampd/ 

11 9/23/15 email from Fuel Tech, cost 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 NOx reduction are very dependent upon a number 

of factors - such as initial NOx level and furnace temperatures. Figure 1 is an example of test data from 

an SNCR optimization program on a pulverized coal-fired boiler that shows NOx reduction 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 program12 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 Sload, A., "Optimizing 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.com 
Figure 2. NOx reduction versus baseline NOx for coal-fired EGUs13 

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 NOx levels 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 rate14 

.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.com 
Figure 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% 

o ----- -- ---- ~ ! I .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 & Lundy16 (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 ranging 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 Sargent & Lundy, IPM Model - Updates to Cost and Performance for APC Technologies SNCR Cost Development 

Methodology Final March 2013 Project 12847-002 

www.AndoverTechnology.com 
SCR 

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, emission 

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 Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014 

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 System Studies, Cost 

Estimation Methodology for NETL Assessments of Power 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 INDUSTRIES 

21 US 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 2011, pg 

4. 

22 Andover 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) 

160,000 

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 2014 2015 

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. 

23Cichanowicz, J. E., "CURRENT CAPITAL COST AND COST-EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL 

TECHNOLOGIES", Prepared for Utility Air Regulatory Group, January 2013 

www.AndoverTechnology.com 
As 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 database24 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 avoid the catalyst deactivation from gaseous 

phosphorus.26 If this 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 of 15% is too high in light of the 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 Gadgil 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 Using Combustion 

Additives: 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 

directed toward the "study" estimate with a nominal accuracy of± 30% percent. According to 

Perry's Chemical Engineer's Handbook, a study estimate is " ... used to estimate the economic 

feasibil ity of a project before expending significant 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 1.31 

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.com 
Table 1. Classifications of Cost Estimates32 

Primary C/Jaracteristic Secondaty Characteri5tic 

M ATURITY LEVEL OF 

PROJECT DEFINITION END USAGE EXPECTED ACCURACY 

ESTIMATE METHODOLOGY RANGE 

CLASS DELIVERABLES Typical purpose of Typical estimating method Typ1cal variation in low and high Expressed as % of complete estimate 

ranges rt! 

de inhion 

Concept Capacity factored, L: -20% to -50% Class S O%to 2% parametric mode.ls, screening judgment, or analogy 

H: +30% o+l00% 

1%to 15% 

S udy or Equipment factored or L: ·15%to -30% 

Class 4 feasibility parametric models H: +20%to +50% 

Budget Semi-detailed unit costs 

l.: -10% to -20% 

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/ten de 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 technology, availability of applicable reference cost data, and many other risks affea the range markedlv. The 

+f· value represents t~'l)ical percentage variation of aaual costs from the cost estimate after application of contmgen<y (typically at 

a SO'!". level 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, NOx level, 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.com 
Table 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 

Initial Ammonia(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 Units 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 Vol. 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 PacifiCorp's BART Analysis Update for Hunter Units 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_cJH~~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!:!'lt rnlilllnq 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 

CIVIL WORK - ....,. __ ._ 

----- -·---------'"<ffNHC~""-='" __ ,, ___ ,_,m ___ ,,_ -----·-

2.4.00.00 ARCHJTECTURAl 

,.JG 

alH lt'o• i'Zef 

AHCHITECTURAL 

31 41.9~ Fire Prote<:tion Eauit'lffle-nt. & Svstem. lJse.r DefiM<i 

I fine 'Pl'!l(ecilcn Eqtt~ !. ~m I Fire WJ:'O{M..sloo sy~,;m or UA T 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 Federal Register 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. 41 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 of the installation. This generally 

includes general facilities and engineering costs such as construction and contractor fees, 

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 Division 

www.AndoverTechnology.com 
preproduction costs such as startup and testing, inventory capital and any process and project 

contingency costs. " 

Per Table 2.5, on page 2-44 Section 4.2 Chapter 2 of the 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 dimensions of modules. 90 modules, assuming typical module 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 PARKER STREET, LAKELAND, FL. 

33801, Bid Number: 5266A, Title: Unit 3 SCR Catalyst Layer Replacement, Date: 9/23/2015 

Memorandum, To Mayor and City Commission, From City Attorney's Office, Re : Approval to Procure Services with SCR-Tech to 

Regenerate Catalyst Layers for Mcintosh Power Plant Unit 3 Selective Catalytic Redu ct ion Reactor System, January 4, 

2016 

44 Memorandum, To Mayor and City Commission, From City Attorney's Office, Re: Approval to Procure Services with SCR-Tech 

to Regenerate 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 Register I Vol. 79, No. 20 I Thursday, January 30, 2014 I Rules and Regulations, pg 5143 

www.AndoverTechnology.com 
9. Operating Cost - Cost of generating steam for 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 energy 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, 

$/MM Btu 

Hunter 1 1.9590 

Hunter 2 1.9080 

Huntington 1 1.8300 

Huntington 2 1.8300 

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Assumptions 

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 MM Btu 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 historica l emissions and heat input data were developed from the EPA Air Markets 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 Control 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 PacifiCorp's BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014 

www.AndoverTechnology.com 
Table 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/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/MM Btu) 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/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/MM Btu) 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 $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 

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Table 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, August 5, 2014 

www.AndoverTechnology.com 
Table 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 

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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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