Cost of NOxBART Controls on Controls on Controls on UtahEGUs 

to: 

 

EC/R Incorporated 

501 Eastowne Drive, Suite 250 

Chapel Hill, NC 27514 

 

October 22, 2015 

Andover Technology Partners Andover Technology Partners 

112 Tucker Farm Road, North Andover, MA 01845 

phone: (978) 683-9599; e-mail: staudt@AndoverTechnology.com 
Andover Technology Partners Andover Technology Partners

 112 Tucker Farm Road, North Andover, MA 01845 
Contents

Sections Page 

1. Background 1 

2. NOx Control Cost Methodology 2 

 

 PacifiCorp Hunter Units 1 & 2 22 

 PacifiCorp Huntington Units 1 & 2 24 

 
www.AndoverTechnology.com 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

NOxControl Cost Methodology 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 Overfire 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 

 Sargent & 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 Public Comment (“the 2015 SNCR CCM”) 

 Chapter 2 Selective Catalytic Reduction, —6/5/2015 – Draft for Public 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 

 PacifiCorp BART Analysis of Hunter Unit 1, July 2, 2012 
www.AndoverTechnology.com 3

• 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 EPA Air Pollution Control Cost Manual, and the 

methodology used here for estimating costs is consistent with the recommendations in the manual, 

such as use of overnight cost9 for capital cost. 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.10 Capacity factors used in cost estimates were estimated from 

historical US EPA Air Markets Program Data11 for the four units. 

Reagent costs are from a recent estimate.12

Detailed cost estimates are provided in the Microsoft Excel Workbook that is provided with this 

report: 

• Microsoft Excel Workbook UT EGU BART_ Costs.xlsx 

 

 

 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

 “Overnight” costs means capital costs are expressed in constant dollars for the base year, excluding Allowance for Funds 

Used During Construction (AFUDC) 

10 PacifiCorp FERC Form 1, Quarter 4, 2014, pages 402.1, 403.1, 402.2 , line 35 

11 http://ampd.epa.gov/ampd/ 

12 9/23/15 email from Fuel Tech, cost of $1.60 per gallon 25% to 30% less for prill. 
www.AndoverTechnology.com 4

Combustion Controls 

For combustion controls, capital and operating and maintenance cost estimates provided in 

PacifiCorp’s August 2014 estimate were used. 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. 

SNCR

For SNCR the capital cost provided in PacifiCorp’s August 2014 estimate was used, excluding 

AFUDC. 

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. 

Figure 1. NOx Reduction and Reagent Utilization versus reagent treatment rate in NSR for a Pulverized 

Coal-Fired Boiler during an SNCR optimization program 13

(data points plotted below the curves are at unoptimized conditions) 

 

13 Staudt, J.E., Kehrer, K., Poczynek, J., Cote, R., Pierce, R., Afonso, R., Miles, D., and Sload, A., "Optimizing Selective NonCatalytic 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 5

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. 

Figure 2. NOx reduction versus baseline NOx for coal-fired EGUs14

Equation 1 and Figure 3 are taken from the 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 rate15

 

 

14 Chapter 1, Selective Noncatalytic Reduction, —6/5/2015 – Draft for Public Comment 

15 US EPA, Air Pollution Control Cost Manual, EPA/452/B-02-001, 2002, Section 4.2, Page 1-25 
www.AndoverTechnology.com 6

Figure 3. Estimates of SNCR treatment rate as a function of inlet NOx

15

Other elements of SNCR variable operating cost and fixed operating cost are estimated using 

IPM algorithms16 (which happen to be consistent with the 2015 draft SNCR chapter of the 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 using the cost manual or IPM algorithms 

(about $0.30/kW-yr). Without better explanation of these costs, the fixed operating cost of about 

$0.30/kW-yr determined using IPM and CCM algorithms are used. 

 

 

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 7

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 spreadsheet attached with this report. 

In addition, historical industry cost data were considered to determine if the costs were 

reasonable in the context of what has been reported at other facilities.18, 19 For example, as shown in 

the worksheet TVA_SCR_Cost in the attached workbook UT_EGU BART Costs, over twenty SCRs 

installed at TVA plants cost from about $104/kW to $318/kW, using the CEPCI to adjust capital costs to

2014 dollars. Cichanowicz (2013) also found SCR costs to cover a very wide range, but at a higher level, 

with some units as high as over $500/kW. Other examples of SCR systems in 2014 dollars (adjusted 

using the CEPCI) include Montour Station at a cost of $209/kW, Ashville at $216/kW, Belews Creek at 

$289/kW and DTE Monroe at $420/kW.20

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. 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.” 

According to that document, for commercially available technologies process contingency 

could range from 0-10%. 

When the CCM was issued in January 2002, SCR had been deployed in Europe and was 

commercially available but was only emerging in application on coal-fired utility boilers in the United 

 

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

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

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

19 SCR Cost from Defendant's Response to Plaintiff's Interrogatory #8, North Carolina v. TVA, Filed with US District Court, 

Asheville, NC, September 1, 2006. 

20 Costs shown in TVA_SCR Cost worksheet of UT_EGU BART Costs workbook 

 http://pplweb.mediaroom.com/index.php?s=12270&item=16522

 Annual NC Clean Smokestacks Act Compliance Report, Progress Energy Carolinas, March 30, 2006 

 http://www.asheville.com/news/dukepoweremission.html

 PR Newswire , “DTE Energy Environmental Project Will Create 900 Jobs” 

21 US Department of Energy, National Energy Technology Laboratory, “Cost Estimating Methodology for NETL Assessments of 

Power Plant Performance”, DOE/NETL-2011/1455, April 2011, pg 4. 
www.AndoverTechnology.com 8

States. According to a study by Cichanowicz,22 at the end of 2001, there were only about 13,000 MW of 

coal SCR capacity in the United States, with nearly all installed in the prior two years, meaning that

there was very limited long-term experience with SCR on US coals. SCR usage on coal-fired boilers has

since increased over ten times to about 143,000 MW of coal capacity (over 50% of the 280,000 MW of 

current coal capacity) with most in operation for more than ten years. SCR is therefore a very well 

proven and well understood technology on a wide range of US coals. As a result, the process 

contingency for SCR on coal-fired utility boilers should be much lower today than what it was when the

CCM was issued in January 2002 – 5%. For SCR applications on utility boilers burning US western 

bituminous coals there should not be a need for process contingency. 

2. Project Contingency of 15% is too high in light of the cost method used and very conservative 

underlying assumptions. 

The cost estimates developed for PacifiCorp are already fairly conservative, allowing for 

overtime due to longer shifts, per diem, small tools charges and other factors, and the 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 the 2002 SCR CCM, 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.” 

The methods and cost elements of the 2002 CCM were adapted from the American Association 

of Cost Engineers, or AACE (CCM Section 1, Chapter 2, p 2-5). AACE 16R-9023 states that, “Project 

Contingency is included to cover the costs that would result if a detailed-type costing was followed as 

in a definitive-type study.” According to NETL,24 “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.” AACE 18R-9725 defines different classes of estimates, from 5 (least detailed) to 1 

(most detailed). The methodology used in the CCM falls into a Class 4 or Class 5, while the 

methodology used by PacifiCorp in their comments, with hundreds of line items and input parameters, 

is clearly a far more detailed estimate that leaves out very little, if any, project scope. Therefore, the 

cost estimate provided by PacifiCorp would fall into a Class 1 or 2 estimate rather than Class 4 or 5 

estimate. 

For this reason, the 15% project contingency factor in the CCM for SCR shown in Table 2.5 on 

page 2-44 of Section 4.2 Chapter 2 is based upon use of the cost estimating method described in the 

CCM to develop the Total Direct Capital Costs. It is not intended to apply to a detailed estimate that: 

 

22 From data in Cichanowicz, J., Muzio, L., Hein, M., “The First 100 GW of SCR in the U.S., - What Have We Learned?”, 2006 

Mega Symposium 

23 AACE Recommended Practice, AACE 16R-90; www.aacei.org/non/rps/18R-90.pdf

24 US Department of Energy, National Energy Technology Laboratory, “Cost Estimating Methodology for NETL Assessments of 

Power Plant Performance”, DOE/NETL-2011/1455, April 2011, pg 5. 

25 AACE Recommended Practice, AACE 18R-87; www.aacei.org/non/rps/18R-97.pdf
www.AndoverTechnology.com 9

• Includes many cost line items that are not explicitly included in the estimating method 

described in the CCM to develop the Total Direct Capital Costs and meant to be included in 

the 15% project contingency, and 

• Already has substantial contingency built into it through conservative assumptions. 

In fact, the 2002 CCM discusses the importance of not double-counting contingency in multiple 

places such as retrofit factor and contingency at page 2-30 of Chapter 2 - Cost Estimation: Concepts and 

Methodology. 

“Due to the uncertain nature of many estimates, analysts may want to add an additional 

contingency (i.e., uncertainty) factor to their estimate. However, the retrofit factor is a kind of 

contingency factor and the cost analyst must be careful to not impose a double penalty on the 

system for the same unforeseen conditions. Retrofit factors should be reserved for those items 

directly related to the demolition, fabrication, and installation of the control system. A 

contingency factor should be reserved (and applied to) only those items that could incur a 

reasonable but unanticipated increase but are not directly related to the demolition, 

fabrication, and installation of the system. For example, a hundred year flood may postpone 

delivery of materials, but their arrival at the job site is not a problem unique to a retrofit 

situation.” (Emphasis added.) 

The 2002 CCM, therefore, explicitly anticipates that some analysts may, incorrectly, apply 

multiple contingencies for the same areas of cost even when using the methods described in the CCM 

for estimating Total Direct Capital Costs. The CCM is clear that such double-counting should be 

avoided. 

Because the cost estimates developed for PacifiCorp are already very conservative and based 

upon detailed estimates of the labor and materials to build the SCR, rather than study-level (class 4 or 

5) estimates, they have double-counted both the costs that are intended by the CCM to be included in 

the project contingency when using the CCM method, plus they have added additional contingency in 

the form of conservative assumptions to address uncertainties in their estimate. For this reason a 15% 

project contingency is excessive for their estimates. In light of the very conservative estimates they 

already developed and the comprehensive nature of those estimates, no additional project contingency 

is allowed. 

3. General Facilities 

General Facilities are costs that are not directly associated with the process equipment, and 

include such things as access roads, safety equipment (such as eye-wash stations), general access, etc. 

On the other hand, ductwork, piping, structural steel to support process equipment and process 

auxiliaries (such as air compressors or cooling water) do not fall into the category of General Facilities. 

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 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 4. 
www.AndoverTechnology.com 10

Figure 4. General Facilities items in the detailed Conceptual Cost estimate. 

4. AFUDC 

AFUDC is not included in the overnight cost methodology of the CCM and therefore was not 

allowed. PacifiCorp correctly excluded this from their estimate. 

5. Sales Taxes 

Sales taxes are excluded from the PacifiCorp cost estimate, as these do not apply to 

environmental upgrades in Utah.26

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. 27 A tax rate of 1.0%, 

 

26 HEAL UTAH * NATIONAL PARKS CONSERVATION ASSOCIATION *SIERRA CLUB, Comments on Proposed 

Amendments to Utah’s Regional Haze Rule, December 22, 2014 
www.AndoverTechnology.com 11

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.28 The 

payment equivalent of the net present value is used to determine the annual equivalent payment per 

Equation 2.7 of Section 1 of the 2002 CCM. 

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, 

preproduction costs such as startup and testing, inventory capital and any process and project 

contingency costs.”

As a result, several costs cited in PacifiCorp’s cost estimate, such as Contractor Construction 

Management / Field Engineering and Contractor Training Classes, are not allowed because these are 

included in the 10% Engineering and Home office fees that are already included in the cost. 

8. Catalyst and Catalyst reactor 

Sargent & Lundy arrives at a catalyst cost by escalating a 1998 cost of catalyst using the CEPCI, which 

does not consider what catalyst actually costs today. As shown in Figure 5. Roughly $5,500 per cubic

meter is a reasonable value for anticipated future catalyst prices. However, most replacement catalyst 

in the United States is regenerated catalyst, and is substantially less expensive than new catalyst.29, 30 

PacifiCorp assumes different catalyst costs in different locations of their August 2014 estimate. 

PacifCorp assumes new catalyst cost of $240/ft3 ($8,600/m3) and replacement cost of $290/ft3

($10,400/m3) on pages 21, 27, 33, and 39 of their August 2014 BART submittal. On the other hand, in 

their Conceptual Cost estimate of the same submittal (see pages 54, 65 89, and 100) they assume 1040 

cubic meters at a cost of $6,750,000 (see item 31.53.15), or $6,500/m3 with additional cost of labor for 

installation. These costs are at the upper level to well above what catalyst actually costs. Furthermore, 

the escalation in catalyst prices assumed by Sargent & Lundy appears excessive based upon 

Cichanowicz’s information shown in Figure 5. Therefore, an assumed current and future catalyst price 

of $5500 per cubic meter is a reasonable price for catalyst – especially in light of the availability and 

lower cost of recycled catalyst – roughly half the price of new catalyst.29, 30 The initial catalyst charge is 

included in the capital cost and future replacement cost is incorporated into the operating cost. 

Adjustments are therefore made to both the capital and operating costs for the SCR that were 

developed for PacifiCorp. 

 

27

 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014, page 47 

28 Class 8 , Machinery and Equipment schedule, from 2015 Recommended Personal Property Valuation Schedules and 

Registered Vehicle Uniform Fees, Utah State Tax Commisssion, Property Tax Division 

29 Hartenstein, H., Servatius, P., Schluttig, A. “Lifetime Extension of SCR-DeNOx Catalysts Using SCR-Tech’s High Efficiency 

Ultrasonic Regeneration Process”, Coal-Gen Chicago, Illinois, July 25-27, 2001 

30 Hartenstein, H., “German Experience with Catalyst Regeneration”, 2007 NOx Round Table and Expo, Cincinnati, Feb 5-6, 

2007 
www.AndoverTechnology.com 12

Figure 5. SCR Catalyst Prices.31

Sargent & Lundy has estimated 1040 cubic meters of catalyst. The estimate by Sargent & 

Lundy of catalyst volume appears to be too great – two reactors each with about 520 cubic meters of 

catalyst. See line 55 of the EPA cost effectiveness comparison (Appendix A) for each of the units in the 

August 5, 2014 PacifiCorp document (pages 22, 28, 34, and 55). This is roughly double the amount of 

catalyst that would normally be expected for units of this size. For example, a 350 MMBtu/hr (roughly

35 MW) coal-fired boiler would require about 42 m3 of catalyst.32 Table 1 also shows examples of 

power plants with SCRs installed along with the catalyst volume. Except for Comanche, which has very 

low NOx reduction, the catalyst volumes are generally in the range of 0.89 to 1.38 cubic meters per 

MW of capacity while the estimate for PacifiCorp is well over 2 cubic meters per MW. PacifiCorp did 

not provide any discussion to explain why the catalyst volume was so large for the Hunter and 

Huntington units. Explanations might include extremely high deactivation rates, but this is not 

discussed at any point in PacifiCorp’s documentation. For that matter, there is no reason to believe 

that the coals burned at these plants should have unusually high deactivation rates. A review of USGS

Coal Quality Data33 for catalyst poisons showed that the Utah coals had arsenic contents typically 

below 1 ppm and rarely more than a few ppm, well below most eastern bituminous coals, and sodium, 

potassium and phosphorus levels were consistent with or generally lower than Pennsylvania 

bituminous coals, which are currently used with SCR equipped facilities. Calcium oxide in the ash, while 

higher than for Pennsylvania coals, was below that of Powder River Basin coals. 

 

31 J. Edward Cichanowicz, CURRENT CAPITAL COST AND COST-EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL 

TECHNOLOGIE, Prepared for, Utility Air Regulatory Group, July 2013 

32 US EPA, Air Pollution Control Technology Fact Sheet, http://www3.epa.gov/ttn/catc/dir1/fscr.pdf 

33 Database is available at http://energy.er.usgs.gov/coalqual.htm 
www.AndoverTechnology.com 13

Sargent & Lundy’s estimate appears to be based upon “Naughton 3 actual catalyst volumes”.34 

However, this is misleading since Naughton 3 has not constructed an SCR. In fact, the owners plan to 

convert the unit to natural gas.35

 

Table 1. High Dust Coal-Fired SCRs in the United States 

Plant Unit MW % Red’n Catalyst 

Volume m3

Lifetime, 

hrs or yrs 

NH3 slip, 

ppm 

Reference

Montour 1 745 90 671 (HC) 2 yrs 2 36

Montour 2 755 90 671 (HC) 2 yrs 2 36

Trimble Cty 547 90 674.6 (plate) NA 2 37

Spruce 2 800 64 1100 (HC) 26,280 2 38

Comanche 3 800 36 400 (Cor) 24,000 2 38

Iatan 1 670 77 800 (HC) 24,000 2 38

Iatan 2 900 68 800 (HC) 24,000 2 38

Cope 1 430 90 426 (HC) 16,000 2 38

St John River 2 units 670 each 85 770 each (HC) 18,000 39

AES Somerset 675 90 897 (plate) 24,000 3 40

Hawthorn 500 55.6 477 (plate) 24,000 2 40

Catalyst is indicated as honeycomb (HC), corrugated (Cor), or plate (plate)

NA means data was not available in paper 

To determine a more reasonable catalyst volume, an independent calculation of catalyst 

volume was made using two methods: 1) using empirical Equations 2.22-2.27 of the 2015 CCM, and 2) 

using the projected activity method using equation 2.21 of the 2015 CCM. 

Catalyst Volume Using Empirical Approach 

The empirical equation 2.22 is used in worksheet NOx-SCR_$ton lines 63-71 of the workbook 

UT_EGU BART Costs to estimate catalyst volume. It results in a total catalyst volume of roughly 500 

cubic meters – which is more consistent with normal practice and the data in Table 1. In addition, 

 

34 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014, see pdf page 22 

35 PUBLIC UTILITY COMMISSION OF OREGON STAFF REPORT PUBLIC MEETING DATE: March 17, 2014; 

http://www.puc.state.or.us/meetings/pmemos/2014/031714/reg1-LC%2057.pdf

 BEFORE THE PUBLIC UTILITY COMMISSION OF OREGON LC 57; “In the Matter of PACIFICORP, dba PACIFIC POWER ORDER; 

2013 Integrated Resource Plan. DISPOSITION: 2013 IRP ACKNOWLEDGED WITH EXCEPTIONS AND REVISIONS JUL 0 8 

2014 

 PacifiCorp, Exhibit RR of Reply Testimony, Summary of Alternative Compliance Technology Solutions, 1-3-2014 

36 Glaser, R., Licata, A., Robinson, T., “THE SCR RETROFIT AT THE MONTOUR STEAM ELECTRIC STATION”, Presented at the 

Electric Power Generation Association,, October 24-25, 2000,, Hershey, Pennsylvania 

37 Saudners, E., Straight, S., et. al., “SCR SYSTEM PERFORMANCE AT LG&E’S TRIMBLE COUNTY GENERATING STATION”, 

Presented at the EPRI Workshop on Selective Catalytic Reduction, October 22-23, 2002, Atlanta, Georgia

38 Buschmann, J., Cohen, M., “New Developments in NOx Reduction”, Coal Gen, August 17-19, 2011,Columbus, OH 

39 Smith, et. al. “St. Johns River Power Park 2 x 670 MW SCR - Designed to Ensure Fuel Flexibility”, The Mega Symposium, 

Paper #96, Baltimore, MD, August 25-28, Baltimore, MD

40 Calvello, J., “Recent Coal Fired SCR Operating Experience in the USA” 2001, EPRI NOx Workshop, Nov 12-17, 2001 
www.AndoverTechnology.com 14

32,000 hours between catalyst changes as assumed by Sargent & Lundy is quite unusual, and as shown 

in Table 1, lifetimes of 16,000 hours or 24,000 hours are more common. 

Catalyst Volume Using Projected Catalyst Activity Approach 

As a second check, the projected catalyst activity method is also used in lines 73-85 of the NOxSCR_$ton worksheet. This uses equation 2.21 of the 2015 CCM, and this method is more consistent 

with how a catalyst supplier would estimate catalyst volume in that catalyst lifetime, deactivation rate 

and catalyst design characteristics are incorporated into this method.41 With this method it is 

necessary to estimate the activity level for the new catalyst. As shown in Figure 6, which demonstrates 

the impact of test conditions on measured catalyst activity, the activity K was 45 m/hr for a 1 meter 

long sample in a test reactor with a velocity of 15 ft/sec (4.6 m/sec). This demonstrates that an 

assumed ko of 42.5 m/h as a starting point for the SCR catalyst sizing is reasonable and conservative. 

Other references show new catalyst activity in the range of 42.742 and about 42.5 m/h.43 Based upon 

these sources, an assumption of 42.5 m/h is assumed. 

Figure 6. Calculated Effect of Velocity on Measured Catalyst Activity, K 44

Specific surface area of the catalyst must be determined. In selecting the catalyst, the dust 

loading should be considered. Table 2 shows the plate catalyst or honeycomb catalyst pitch for 

different dust loadings. Based upon EIA Schedule 923 data for 2014, the fuel burned at the Hunter and 

 

41 John Cochran, “Fuel Impacts on Design and Performance of Catalysts”, McIlvaine “Hot Topic Hour”, June 30, 2011 

 Ken Jeffers, “SCR Catalyst Management “, 2008 WPCA/Ameren ESP and SCR Seminar, Effingham, IL, August 20, 2008 

42 US Patent 7741239, Table 3 

43 Hartenstein, “German Experience with Catalyst Regeneration”, 2007 NOx Round Table and Expo, February 5-6, 2007, see 

slide 12. X and Y axis labels are apparently transposed. 

44 Electric Power Research Institute, Protocol for Laboratory Testing SCR Catalyst Samples 1012666, Final Report, December 

2006, see Fig 3-1; as described in this document, K calculated using normal rather than actual flowrates and 

therefore normal flowrates are used in equation 2.21 to determine catalyst volume. 
www.AndoverTechnology.com 15

Huntington plants averages about 10% fly ash, which would roughly result in a little under 6 grain/dscf. 

This would permit a honeycomb of perhaps 7.4 mm or 8.2 mm pitch. An 8.2 mm pitch catalyst will 

have a lower chance of plugging and is therefore selected. Neglecting any plugged cells, honeycomb 

catalyst with a pitch of 8.2 mm and 1 mm wall thickness has a specific surface area that can be 

estimated by multiplying the circumference of each cell (equal to four times the pitch minus the wall 

thickness, or 4*(p-t)) times the number of cells per square meter (equal to the square of one meter 

divided by the pitch, or (1/p)^2) and then multiply by an assumed catalyst depth of one meter. For a 

honeycomb catalyst with 8.2 mm pitch and 1 mm wall thickness, this results in 428 m2

/m3, and this 

calculation is shown in cell N83 of worksheet NOx-SCR_$ton. 

Table 2. Catalyst pitch selection for different dust loadings45

Finally, a deactivation rate must be assumed to estimate future activity. Table 3 shows 

deactivation rates for different coals. Since the units use bituminous coals, k/ko = 0.70 is assumed.

Table 3. Deactivation rates for different coal types45

Coal Time, hr k/ko Inferred highest deactivation rate per 

hour (1/τ, for lowest k/ko)46

Low Dust 16,000 0.80-0.85 1.39E-05 

Bituminous 16,000 0.70-0.75 2.23E-05 

PRB 16,000 0.65-0.70 2.69E-05 

Lignite 16,000 0.50-0.55 4.33E-05 

In using Equation 2.21, it is important to be consistent between the procedure used in 

determining catalyst activity and the use of that catalyst activity value in estimating catalyst volume. 

Industry convention (as described in Reference 47) is to calculate catalyst activity from laboratory tests 

 

45 Ken Jeffers, “SCR Catalyst Management “, 2008 WPCA/Ameren ESP and SCR Seminar, Effingham, IL, August 20, 2008 

46 Estimated using Equation 2.2 of the 2015 CCM 

47 Electric Power Research Institute, Protocol for Laboratory Testing SCR Catalyst Samples 1012666, Final Report, December 

2006 
www.AndoverTechnology.com 16

under representative conditions; however, catalyst activity is then represented in terms of volume 

flowrates at normal conditions. This has the benefit of providing consistent measures of catalyst 

activity across the industry. Therefore, when using catalyst activity values determined with this 

procedure for calculating catalyst volume with Equation 2.21, SCR system volume flowrate adjusted to 

normal conditions should be used in Equation 2.21 rather than the actual volume flowrate, as 

demonstrated in Reference 48. With a 15% additional allowance for plugging and a 16,000 hour time 

before the first catalyst replacement and using equation 2.21, these assumptions result in catalyst 

volumes estimated at 577 cubic meters (using the maximum catalyst size estimated for the four units). 

Therefore, the estimated catalyst volume of 1040 cubic meters used by PacifiCorp is well in 

excess of what is expected from other facilities or from other methods for estimating catalyst volume. 

The two other methods result in catalyst volumes in roughly the same range and volumes that are 

consistent with what has been used in other high-dust coal-fired EGU applications. 

Conservatively using the highest estimated catalyst volume of the two methods, a catalyst 

volume of 577 cubic meters and a catalyst lifetime until the first catalyst addition of 16,000 hours is 

assumed in this analysis. 

An increase in catalyst lifetime to 32,000 hours would not explain the high catalyst volume 

estimated by Sargent & Lundy. For bituminous coals k/ko between 0.70 and 0.75 is expected after 

16,000 hours, or a reduction in activity of between 25% and 30% every 16,000 hours.49 Therefore, 

given that catalyst activity decays at an exponential rate given by Equation 2.2 of the 2015 CCM and 

volume is determined by Equation 2.21, an increase in volume to go from 16,000 hours to 32,000 hours 

should be equal to between about 1/0.75 to 1/0.70, or between 1.33 to 1.43, or no more than about 

43% more catalyst – not a near doubling of catalyst size. 

Impact on SCR Reactor and associated equipment 

As a result of the much lower catalyst volume, it is necessary to make several adjustments to 

the PacifiCorp estimate for both the catalyst and the SCR reactor cost. Only one reactor is necessary as 

opposed to two. This is because only about half as much catalyst is actually necessary (577 m3). 

Drawings prepared by Sargent & Lundy and submitted by PacifiCorp with their August 5, 2014 BART 

analysis show two reactors, each with a square cross section with each side between 40 feet and 50 

feet. 50 To calculate gas volume, the factors in Table 4 can be used to aid in calculations of gas flow and 

were determined with calculations using EPA’s CUECOST for different coals in the CUECOST coal 

database.51

 

 

48 John Cochran, “Fuel Impacts on Design and Performance of Catalysts”, McIlvaine “Hot Topic Hour”, June 30, 2011 

49 Jeffers, K., “SCR Catalyst Management”, 2008 WPCA/Ameren, ESP and SCR Seminar Effingham, IL August 20, 2008 

50 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014, see pdf pages 79 

and 114 

51 http://www3.epa.gov/ttncatc1/products.html 
www.AndoverTechnology.com 17

Table 4. Flue gas estimates for different coals at different combustion air conditions estimated with 

CUECOST 

units % air Jefferson, 

OH 

Logan, 

WV 

No. 6 

Illinois 

Wyoming 

PRB 

Lignite, 

ND 

Total Dry lbmole/MMBtu 120% 30.2 30.0 30.2 30.4 30.8 

Total Wet lbmole/MMBtu 120% 33.0 32.8 33.5 35.1 35.7 

Total Dry lbmole/MMBtu 115% 29.0 28.7 28.9 29.1 29.5 

Total Wet lbmole/MMBtu 115% 31.7 31.5 32.2 33.8 34.4 

The inlet gas velocity and catalyst channel velocity for one reactor of 50 feet to a side was 

calculated and it is sufficiently low.52 Since the reactor will likely remain roughly the same height, 

having three layers initially installed, the cross sectional area of the catalyst reactors will be reduced 

roughly in proportion to the catalyst volume, which will reduce the perimeter of the reactor vessel, 

thereby reducing the material needed for the SCR reactor vessel roughly in proportion to the reduced 

perimeter. Using this approach to estimate the reduction in cost for a single reactor vessel, an 

approximation is to use the square root of the change in cross sectional area so that if the cross 

sectional area were cut in half as a result of catalyst volume being cut in half, roughly 71% (square root 

of 0.5) of the materials would be used for the reactor. 

On the other hand, Sargent & Lundy assumed two SCR reactors. Assuming a common wall 

rather than two completely separate reactors, the reduction can also be estimated as going from seven 

walls (three for each reactor plus the one common) to four walls, or 4/7 or 57% of the labor and 

materials (SCR vessel casing, hood, gallery insulation, etc.) to build one SCR vessel versus two. Going 

from two separate reactors to one would go from 8 walls to 4, or a roughly 50% reduction. To be 

conservative, the ratio of the square root of the ratio of the volume of catalyst was used (roughly 0.74). 

The reduced catalyst perimeter provides a rough estimate of the reduced surface area (as opposed to 

cross sectional area) of the catalyst reactor and associated materials for the reactor. This is an 

approximation, but a conservative one since the reactor hood and inlet, as well as the reactor vessel 

are all scaled in this manner, and ductwork was not scaled down at all although some of the cost for 

ductwork would in fact be reduced by cutting the number of ducts in half, while perhaps making them 

somewhat larger. Items identified in the estimate as Other Direct Costs are scaled down in accordance

with the reduction of direct costs. 

Because only one reactor of roughly the same size as one of the two reactors assumed by 

Sargent & Lundy is necessary, equipment such as sootblowers, sonic horns, LPA screens and static 

mixers are all cut in half versus the estimate by Sargent & Lundy. Also, SCR support steel is cut in half 

because only one reactor with roughly half the total volume of catalyst is needed versus Sargent & 

Lundy’s estimate. 

 

52 See worksheet NOx-SCR_$ton in attached Excel workbook. Lines 29-32. 

Per pg 2-51 of 2015 CCM a superficial velocity of 16 f/s or 5 m/s may be used to estimate cross sectional area 

Also, per Hans Jensen-Holm, Nan-Yu, Jim Jianhua Cui, “Implementation of SCR DeNOx Technology on Coal-Fired Boilers in P.R. 

China”, pg 11 shows channel velocities of 6-7.5 m/s. 
www.AndoverTechnology.com 18

The resulting adjustments to the PacifiCorp estimate are shown in lines 10-20 of worksheet 

SCR_PacifiCorp Annual_Adjusted in the workbook UT_EGU BART Costs. 

Catalyst lifetime also plays a role in the economics and affects the annual allocated cost for 

catalyst replacement. The assumed 32,000 hours before the first layer replacement – or a replacement 

time of four years to the first catalyst addition is unusually high. As Table 1 demonstrates, the most 

common catalyst replacement periods are between 16,000 hours and 24,000 hours. A life of 16,000 

hours, or two years between replacement, is assumed in this analysis. This is conservative in the sense 

that it provides a higher catalyst annual replacement cost and seems generally consistent with both 

practice and other bituminous units. 

9. Cost of Induced Draft (ID) Fan and Auxiliary Load 

Sargent & Lundy has estimated 2090 kW and 2182 kW for load (page 47 of August 2014 

PacifiCorp submittal). Because there are very few electric loads besides the fan, and they are small by 

comparison, the largest single load by far is the increased fan load from the SCR system pressure drop. 

Calculations were performed in the fan power worksheet to estimate fan load based upon pressure 

drop and volume flowrate. The loads estimated by Sargent & Lundy correspond to a combined fan and 

motor efficiency of over 80%.53 Using a combined fan and motor efficiency of 65% and pressure loss 

values per the 2002 CCM,54 results in a load of about 2.7-2.8 MW, or about 3600-3800 hp. This is also 

consistent with the value estimated using the 2015 CCM of about 2.6-2.8 MW.55 Therefore, although 

the load was underestimated, Sargent & Lundy over-estimated the cost of the fans used in the 

PacifiCorp submittal. Two 6000 hp (4475 kW) fans and motors included in the capital cost estimate 

(see line 31.35.00 of Conceptual Cost Estimate on pages 54, 65, 89 and 100 of the August 2014 

submittal) are too large even allowing for 2x100% flow capability. They presume a fan efficiency of 

under 50%, which is too low (see calculations in fan_power worksheet). These large fans would need 

to be throttled or run at less than full speed. Smaller fans properly sized for the load would be a more 

economical choice. Therefore, the cost of the fans in PacifiCorp’s estimate should be reduced. To 

estimate the cost of lower power fans, it is possible to use the algorithm for estimating fan cost in 

CUECOST. 

The CUECOST ID fan cost algorithm in the fabric filter worksheet is 

(97.41*Volume Flow^0.619) 56

This can be used to estimate the cost for lower power fans, although, it is not possible to use it 

directly because the CUECOST algorithm does not account for escalation of costs since that algorithm 

was originally developed. However, since the algorithm demonstrates that cost of a fan is proportional 

to the maximum volume flowrate raised to the 0.619 power, it can be used to scale the costs provided 

 

53 See calculation in fan_power worksheet of UT_EGU_BART_Costs workbook 

54 2002 CCM, Section 1, page 2-32, Section 2 page 2-46, calculation is in fan_power worksheet of UT_EGU_BART_Costs 

workbook 

55 2015 CCM; Equation 2.61 

56Coal Utility Environmental Cost (CUECost) Model Version 1.0 -http://www3.epa.gov/ttncatc1/products.html, see line 59 of 

FF ESP Cost & Tech. Results worksheet 
www.AndoverTechnology.com 19

by Sargent & Lundy for PacifiCorp. Since power is equal to the product of volume flow and pressure 

drop and the pressure drop across the SCR system at full load is unaffected by the choice of fan, we can 

scale cost by horsepower raised to the 0.619 power to estimate the cost of a fan sized for lower power

than 6000 hp. Using this approach, the cost of a 3800 hp motor and fan would be estimated as: 

Cost for 6000 hp fan * (3800/6000)^0.619 

The resulting adjustments to the PacifiCorp estimate are shown in line 21 of worksheet 

SCR_PacifiCorp Annual_Adjusted in the workbook UT_EGU BART Costs. 

Therefore, the adjusted capital cost estimate adjusts for the estimated auxiliary load assuming 

that most of it is from the fan. This is also a conservative estimate because in many cases existing fans 

can be modified to increase their output and overcome the increased pressure drop, and this would be 

a much less costly approach than installing two new fans. 

10. 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 5. PacifiCorp’s cost of energy to heat the steam was therefore 

changed to these values and adjusted for actual capacity factor. 

Table 5. 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.com 20

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 6. These demonstrate that all four units installed 

combustion controls to reduce NOx emissions since 2003. 

Table 6. Reported emission rates for affected EGUs 

Facility Name 

Facility 

ID 

(ORISPL) 

Unit 

ID 

Annual 

Heat Input, 

MMBtu 

2001-03 

avg. 

Avg. NOx Rate (lb/MMBtu) 

2001-

2003 2014 2015 avg Q1, Q2 

AVG after 

comb 

controls 

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 historical 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 

 
www.AndoverTechnology.com 21

Cost Estimating 

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 workbook attached to this report: 

• UT_EGU BART Costs 

The details of the estimating methods are described in the workbook. Consistent with the EPA 

Control Cost Manual,57 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 58 

• 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,59 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.

 

 

57 EPA. 2002. EPA Air Pollution Control Cost Manual (Sixth Edition). EPA/452/B-02-001, p 2-5 - 2-7 

589/23/15 email Fuel Tech 

59 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 22

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 NOx controls, including SNCR and SCR, are 

feasible.60 Detailed cost estimate calculations are provided in the Microsoft Excel workbook provided 

with this report. Table 7 shows the estimated costs of control for each of the Hunter units. 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. 

 

 

60 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014 
www.AndoverTechnology.com 23

Table 7. Hunter Estimated Control Costs

Hunter 1 Cost of controls

 

Combustion Control 

(CC) SNCR SCR CC and SNCR CC and SCR 

Capital Cost, $/kW $26 $17 $221 $43 $247

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 $11,929,013 $3,794,531 $13,090,910

$/Ton $382 $3,796 $4,853 $1,016 $2,380

$/ton Incremental $3,796 $5,268 $3,796 $5,268

Hunter 2 Cost of controls

 

Combustion Control 

(CC) SNCR SCR CC and SNCR CC and SCR 

Capital Cost, $/kW $20 $18 $231 $38 $251

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 0.16 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 $11,854,673 $3,447,199 $12,718,714

$/Ton total $298 $3,913 $5,092 $968 $2,432

$/ton Incremental $3,913 $5,558 $3,913 $5,558

incremental 

versus CC 

incremental 

versus SNCR 

incremental 

versus CC 

incremental 

versus CC and 

SNCR 

 
www.AndoverTechnology.com 24

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.761 Detailed cost estimate calculations are provided in the Microsoft Excel workbook provided 

with this report. Table 8 shows the estimated costs of control for each of the Huntington units. 

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. 

 

 

61 PacifiCorp’s BART Analysis Update for Hunter Units 1 and 2 and Huntington Units 1 and 2, August 5, 2014 
www.AndoverTechnology.com 25

Table 8. Huntington Estimated Control Costs

Huntington 1 Cost of controls

 

Combustion Control 

(CC) SNCR SCR CC and SNCR CC and SCR 

Capital Cost, $/kW $18 $17 $216 $34 $234

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 $11,994,475 $3,497,687 $12,805,229

$/Ton $332 $3,609 $4,522 $1,098 $2,515

$/ton Incremental $3,609 $4,879 $3,609 $4,879

Huntington 2 Cost of controls

 

Combustion Control 

(CC) SNCR SCR CC and SNCR CC and SCR 

Capital Cost, $/kW $21 $17 $222 $38 $243

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 $11,931,528 $3,508,162 $12,872,966

$/Ton $365 $3,730 $4,877 $1,075 $2,563

$/ton Incremental $3,730 $5,326 $3,730 $5,326

incremental 

versus CC 

incremental 

versus SNCR 

incremental 

versus CC 

incremental 

versus CC and 

SNCR