Cost of NOx Controls on Wyoming EGUs to: 

 

EC/R Incorporated

501 Eastowne Drive, Suite 250 

Chapel Hill, NC 27514

October 28, 2013

Final report

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

Sections Page

1. Background 1

2. NOx Control Cost Methodology 2

David Johnston 1-4 29

Jim Bridger 1-4 35

Laramie River 1-3 39

Naughton 1-3 45

Wyodak 52
www.AndoverTechnology.com 1

Background

Andover Technology Partners (ATP) under contract to EC/R (ECR) provided cost estimates for 

NOx controls at the following Wyoming Electricity Generating Units.

• Dave Johnston units 1-4

• Jim Bridger units 1-4

• Naughton units 1-3

• Wyodek unit 1

• Laramie River units 1-3

Previous cost estimates are addressed in two memos and two spreadsheets provided to EC/R on 

February 7, 2013:

• Review of Estimated Compliance Costs for Wyoming Electric Generating (EGUs)—Revision of 

Previous Memo, memo from Jim Staudt, Andover Technology Partners, to Doug Grano, EC/R, 

Inc., February 7, 2013. (Staudt Memo) and associated workbook.

o Microsoft Excel Workbook WY EGU BART_RP Costs_20121019_revised.xlsx

 Which included estimates for all plants except Jim Bridger

• Review of Estimated BART Compliance Costs for Wyoming Electricity Generating Units (EGUs) 

memo from Jim Staudt, Andover Technology Partners, to Doug Grano, EC/R, Inc., February 7, 

2013 and associated workbook

o Microsoft Excel Workbook WY EGU BART_RP Costs_20130201.xlsx

 Which included estimates for Jim Bridger

EPA has since received comments from various stakeholders. After review of the comments, 

ATP has revised its cost estimates for NOx controls on these plants based upon the information in the 

comments that ATP believes provided a valid reason to revise the cost estimates. ATP has provided 

detailed responses to the comments offered by stakeholders in the Responses to Comments (RTCs). In 

this report ATP will address that information that has changed and how the costs have been affected. 

ATP will highlight some of the key issues raised by commenters relating to cost, but will not explore 

them in the level of detail found in the RTCs.
www.AndoverTechnology.com 2

NOx Control Cost Methodology

In response to comments, cost estimates have been revised for the following Wyoming units.

• Dave Johnson, units 1-4

• Jim Bridger, units 1-4

• Laramie River Station, units 1, 2, and 3

• Naughton units 1, 2 and 3

• Wyodak unit 1

For each unit, estimates were made for the following technologies, where applicable:

• Combustion Controls, including Low NOx Burners (LNBs) with Overfire Air (OFA)

• Selective Non-Catalytic Reduction (SNCR)

• Selective Catalytic Reduction (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 advanced combustion controls were 

not in use at these units. Emission rates with 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; these estimates are used in all 

calculations. For each unit, SNCR and SCR costs were estimated in combination with applicable controls.

In estimating the cost of controls, the following were considered:

• IPM Cost models

• US EPA Air Pollution Control Cost Manual1

• Data provided by the facilities in their BART assessments

• Data provided in comments, including in some cases budgetary price estimates from a control 

technology consultant or vendor

• Other data that have been published and are described in more detail

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 inclusion of sales and property taxes (but not impact on income taxes), insurance and 

administrative costs, and the use of overnight cost2 for capital cost. The overnight cost methodology 

does not allow for inclusion of financing costs during construction (also called AFUDC), such as used by 

EPRI as well as in the Integrated Planning Model (IPM).

For each control method, changes from previous cost estimates are noted.

 1 EPA. 2002. EPA Air Pollution Control Cost Manual (Sixth Edition). EPA/452/B-02-001 2 “Overnight” costs means capital costs are expressed in constant dollars for the base year, excluding Allowance 

for Funds Used During Construction (AFUDC)
www.AndoverTechnology.com 3

Combustion Controls

For combustion controls, if the capital and operating cost estimates by the users were available, 

they were used. If not, IPM cost estimates were used to estimate capital and operating costs of 

combustion controls (except that AFUDC is not included).

3

 Percent reduction and tons of NOx removed

were based upon actual emission rates after control installation or projected emission rates if actual

emission rates were not available.

SNCR

For SNCR, except where noted otherwise, capital cost is assumed to be $20/kW. This is a 

simplifying assumption from the IPM algorithm that, as described below, generally yields more accurate 

results. According to the 2008 Institute of Clean Air Companies’ SNCR White Paper,4 “Typical SNCR 

capital costs for utility applications are $5-$15/kW, vendor scope, which corresponds to a maximum of 

$20/kW if balance-of-plant capital requirements are included.” This is also consistent with ATP’s

experience, having worked with the following electric utilities and power plants on their SNCR 

installations as a consultant or as a past employee of Research-Cottrell and Fuel Tech – suppliers of 

SNCR systems.

• Constellation Energy – C P Crane units 1&2 and Wagner Unit 2 5

• Conectiv – Edge Moor unit 3 and Indian River 6

• New England Power – Salem Harbor Station 7

• Montaup Electric – Somerset Unit 8 8

ATP has also published reports that describe the cost and application of technologies used for 

control of NOx, including SNCR.

9, 10 ATP’s opinion is that the IPM algorithm for SNCR capital cost 

assumes economies of scale that don’t really exist to a great extent in SNCR systems, which results in 

over-predicting of capital cost for small systems and under-predicting capital cost for large systems.

Therefore, $20/kW provides a reasonable estimate for the capital cost of SNCR, unless there is 

reason to believe that a more complex or costly SNCR system will be required. Furthermore, due to the

relatively low capital cost of SNCR, the operating cost – especially reagent cost – is the much more 

 3 Documentation for EPA Base Case ver 4.10 Chapter 5, Emission Control Technologies; 

http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.html#documentation, pg 5-7 4 Institute of Clean Air Companies, “White Paper – Selective Non-Catalytic Reduction (SNCR) for Controlling NOx Emissions”, 

February 2008, p 7. 5 Staudt, J, Hoover, B., Trautner, P., McCool, S., Frey, J., “Optimization of Constellation Energy’s SNCR System at Crane Units 1 

and 2 Using Continuous Ammonia Measurement”, The MEGA Symposium, Baltimore, MD, August 31-September 2, 

2010 6 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. 7 Ibid

8 Staudt, J.E., Casill, R.P., Tsai, T., and Arigiano, L., "Commercial Application of Urea SNCR for NOx RACT Compliance on a 112

MWe Electric Utility Pulverized Coal Boiler" presented at the 1995 EPRI/EPA Joint Symposium on Stationary 

Combustion NOx Control, Kansas City, May 16-19, 1995 9 Staudt. J. and M J Bradley & Associates, for the Northeast States for Coordinated Air Use Management, “Control Technologies 

to Reduce Conventional and Hazardous Air Pollutants from Coal-Fired Power Plants”, March 31, 2011 10 "Status Report on NOx: Control Technologies and Cost Effectiveness for Utility Boilers", report for Northeast States for 

Coordinated Air Use Management and Mid Atlantic Regional Air Management Association, June 1998.
www.AndoverTechnology.com 4

important component of cost. Therefore, for the purpose of a BART analysis, this is a simplifying 

assumption that has little impact on the cost-effectiveness calculation.

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 data include 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. Except where furnace temperature data was provided to indicate a 

different utilization rate, for the purpose of making an estimate of reagent consumption for the 

Wyoming pulverized coal units it was assumed that the chemical utilization was 25% and that NOx 

reduction diminished with lower NOx concentrations – 30% for NOx greater than 0.25 lb/MMBtu, 25% 

for NOx between 0.20 and 0.25 lb/MMBtu, and 20% for NOx under 0.20 lb/MMBtu. This is expected to 

provide a reasonable estimate of NOx 

reduction and reagent consumption. 

Figure 1. NOx Reduction and Reagent 

Utilization versus reagent 

treatment rate in NSR for a 

Pulverized Coal Fired Boiler 

during an SNCR optimization 

program 11

(data points plotted below the 

curves are at unoptimized 

conditions) 

A utilization factor of 25% is 

higher than the default utilization 

factor of 15% in the IPM reagent cost calculation; however, 15% is overly conservative and would only 

reflect utilization rate at very high furnace temperatures. For example, information from Fuel Tech, the 

leading supplier of SNCR technology stated that at the unusually high furnace exit temperature of 

2500°F, 25% reduction was possible with an NSR of 1.75 (utilization of 14.3%) while at a unit with an exit 

temperature of 2334°F, 25% reduction was possible at an NSR of 1.1 (utilization equal to 22.7%).12 

Assuming more typical furnace temperatures of 1800 to 2200°F utilization should be well above 22.7% 

for most boilers.

 11 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. 12 Email from Alexander Dainoff to Jim Staudt, June 27, 2012
www.AndoverTechnology.com 5

Because the cost of SNCR is driven largely by the reagent consumption, selection of the correct 

chemical utilization rate is very important. Chemical utilization equals Percent reduction divided by NSR. 

Although the default utilization rate in the IPM algorithm is 15%, as explained in more detail in EPA’s 

responses to comments, these utilization rates are too low to be used in general ; however, if there is 

temperature data indicating an unusually high furnace temperature (utilization drops off with increased 

furnace temperature) lower utilization may result. For more typical furnace temperatures utilization 

rates in the range of 25% are expected. Some commenters indicated that 12% chemical utilization, as 

assumed by Sargent & Lundy in their cost estimates, was a better estimate of utilization rate for Laramie 

River Station. Based upon the furnace temperature data provided by Basin Electric, ATP agrees. 

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

IPM algorithms. A correction was made to the variable operating cost associated with water. This had a 

negligible effect of the results of the cost estimates.

The cost of auxiliary power was changed from the previous estimate. In the original analysis the 

default values for electricity in IPM were used, which reflects the retail market price for power. On the 

other hand, the cost of power used for auxiliary loads should be equal to the cost to the owner of 

generating the electricity rather than the retail price received in the market. ATP has reviewed FERC 

Form 1 data for PacifiCorp13 and has incorporated in the revised costs for each plant the stated cost of 

electricity per net kWh. For Laramie River Station the costs in their July 2008 BART analysis14 are used, 

as these are also more consistent with PacifiCorp’s reported cost of generation than the values later 

used by Basin Electric or by ATP in our original cost analysis, which were more reflective of retail power 

prices rather than the cost to generate.

SCR

Except for Laramie River units 1-3, Dave Johnston 3 and Naughton 1 and 2, Selective Catalytic 

NOx Reduction (SCR) capital cost is estimated using the IPM algorithms with retrofit factors adjusted on 

a unit by unit basis. The retrofit factor is a subjective factor used to account for the estimated difficulty 

of the retrofit that is unique to the facility. Because site visits were not possible, the retrofit factor was 

estimated from satellite images that provide some insight to the configuration of the units and degree of 

congestion around the site and in the vicinity of where the SCR would be installed. These factors impact 

the ability to locate large cranes on the site – that impact how the SCR is assembled (are large sections 

lifted into place or is the SCR “stick built”), how much ductwork is needed, if the SCR must be built onto

a large, elevated steel structure or can be built near the ground, and if other equipment must be 

relocated to accommodate the space of the SCR. When using the IPM capital cost model, retrofit 

difficulties associated with an SCR may result in capital cost increases of up to 50% over the base 

 13 FERC Financial Report, FERC Form No. 1: Annual Report of Mjor Electric Utilities, Licensees and Others and 

Supplemental Form 3Q: Quarterly Financial Report, PacifiCorp, Year/Period of Report 2010/Q4., pgs 402.2, 403, 

403.2, see line 35

14 Black & Veatch, “Basin Electric Power Cooperative Laramie River Station Refined BART Visibility Modeling”, July 

24, 2008, pg 25 of 176
www.AndoverTechnology.com 6

model. 15 In general, ATP tended to use conservative estimates of retrofit factor, with none lower than 

1.0.

Satellite imagery provides a unique, “bird’s eye” view of the site, and can be useful for 

identifying the location of equipment relative to each other, access to and around the boilers for cranes 

and other equipment, access to and from the site, interferences around the site perimeter, availability 

of open areas for temporary storage of construction materials, etc. Therefore, because of its availability 

and the information it yields, satellite imagery is a very useful tool in major retrofits and is widely used 

by air pollution control system original equipment manufacturers (OEMs) to evaluate a retrofit. Site 

visits provide other information that may not be discernible from a satellite image, and are typically 

performed in addition to rather than in lieu of use of satellite images. Information that is gained from a 

site visit may be whether or not a major piece of equipment , like an air preheater, needs to be 

relocated to make room for ductwork. None of the owners reported that relocation of the air preheater 

or other major equipment was necessary. As a result, use of satellite imagery was considered sufficient 

for the purpose of this estimate.

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.

10, 16, 17 Estimates were also 

compared against estimates provided by the facility owners (December 2007, March 2008 and August 

2013 estimates for Dave Johnston and Naughton and, December 2007 and March 2008 estimates for 

Wyodak, and June 2008 and August 2013 estimates for Laramie River). Without exception, owners 

significantly increased their cost estimate from the original estimate. The owners did not provide an 

explanation for the high increase in capital cost between their first and final estimates, although in some 

cases the difference in time between estimates was only 4 months.

Table 1. Owner’s estimates of capital cost for SCR*

(see workbook: WY EGU BART_RP Costs_20130923.xlsx)18

Pant Dave Johnston Naughton Laramie River Wyodak

Unit BW43 BW44 1 2 3 1 2 3 BW91

Capacity, MW 220 330 160 210 330 565 570 570 335

Dec 2007 $/kW SCR $306 $300 $318 $312 $279 $296

March/July 2008 $/kW SCR $510 $436 $531 $509 $415 $218 $218 $218 $474

August 2013 $504 $641 $486 $427 $449 $438

% increase in estimate 65% 46% 102% 56% 49% 96% 108% 103% 60%

* Costs include owner’s cost and Allowance for Funds Used During Construction (AFUDC)

 15 Sargent & Lundy, “IPM Model – Revisions to Cost and Performance for APC Technologies SCR Cost Development 

Methodology FINAL”, August 2010, Project 12301-007, Perrin Quarles Associates, Inc. p 1. 16 Fox, Phyllis, “Revised BART Cost Effectiveness Analysis for Tail-End Selective Catalytic Reduction at the Basin 

Electric Power Cooperative Leland Olds Station Unit 2 Final Report”, RTI Project Number 

0209897.004.095, March 2011 17 Cichanowicz, J. E., “CURRENT CAPITAL COST AND COST-EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL 

TECHNOLOGIES”, Prepared for Utility Air Regulatory Group, January 2010 18 This workbook is discussed in further detail in the Cost Estimating section of this report
www.AndoverTechnology.com 7

 

Figure 2 is taken from Cichanowicz, and shows industry-reported costs for SCRs at different time 

periods, including 2008-2010. Although there was rapid cost escalation in the decade prior to 2008, that 

has stopped. Between 2006 and 2012 the annual Chemical Engineering Plant Cost Index (CEPCI) has 

remained in a range between about 500 and 600 (550±10%), and the monthly CEPCI reached a peak in 

August 2008 at 619.3 and has since remained below that (June 2013 CEPCI was 564.9). As a result, 

2008-2010 costs are on the same basis as those shown above (inclusive of owner’s costs, AFUDC, etc.).

Figure 2. Capital cost of SCRs (in $/kW) for four different time periods, reported by Cichanowicz17

The PacifiCorp estimates in Table 1 for December 2007 and Basin Electric in 2008 were in the 

same range as the actuals reported by Cichanowicz, but the capital costs reported only four months 

later for Dave Johnston, Naughton and Wyodak and more recently for Laramie River Station were near 

or well above the highest costs (in $/kW) reported by Cichanowicz. The most recent estimate for 

Naughton unit 1 is over 40% greater than the highest historical cost reported by Cichanowicz! The 

dramatic increase in estimated cost and the stark inconsistency of the more recent estimated costs with 

other industry data begs more explanation from the owners about their reported costs. At the very 

least, it demonstrates that these cost estimates are extremely conservative.

As noted, the more recent cost estimates provided by owners universally are at the upper 

extreme, or in some cases well beyond the upper extreme of recent costs experienced by the industry

for retrofit of SCR. As will be noted in this report, while there are varying levels of retrofit difficulty at 

these sites, in most cases it was not possible to justify the high costs reported by the owners. In their 

comments none of the owners reported the kind of issues that tend to dramatically increase retrofit 

costs, such as the need for relocation of major pieces of equipment.
www.AndoverTechnology.com 8

Changes to previous cost estimates were made, and these are largely due to the following 

effects:

• Elevation – Elevation does have an impact on the volume of gas treated and the resulting cross 

section of the ductwork, the SCR reactor, the structure needed to support the ductwork and the 

size of additional fan capacity. The elevation of the site is factored into the unit MW size 

accordingly due to its effects on the flue gas volume. This had a significant impact on capital 

cost.

• Reagent – The facilities will be using anhydrous ammonia rather than urea, As a result, the 

variable operating cost was changed to accommodate ammonia rather than urea. This will not 

make a signficant change to the reagent storage cost or to other costs. In fact, anhydrous 

ammonia storage systems tend to be less expensive than urea systems because they do not 

require a urea to ammonia conversion system. So, the IPM cost model should provide a 

conservative estimate of the reagent storage and handling system.

• As noted earlier in this report, the auxiliary power cost was changed to equal the cost of 

generation rather than the market price of power sold.

• In the cases of Laramie River units 1-3, Naughton 1 & 2 and Dave Johnston 3, ATP used parts of 

the owner’s estimated capital cost, but excluded other costs.

• For Dave Johnston 3 and Naughton units 1 and 2, alternatives were evaluated for plant lifetimes 

under 20 years based upon comments received from PacifiCorp.

• SCR and LNB capital costs using the IPM were escalated from previous cost (2010) to 2013 

dollars using the June 2013 CEPCI. SNCR costs were not escalated because the capital cost has 

so little impact on SNCR cost and because using the CEPCI to escalate from 2008 (the year of the 

ICAC White Paper) to 2013 would result in a drop in cost (CEPCI is lower in 2013 than 2008). The 

costs for already insrtalled combustion controls were not escalated.

Assumptions

In estimating cost of control, it is assumed that a full complement of combustion controls are 

implemented prior to installation of post-combustion controls (SNCR and SCR). Emissions rates for the 

2001-2003 period were used to estimate the emission rate prior to installation of combustion controls.

The average reported emission rates for 2001-2003, 2011, 2012 and 2013 (quarters 1 & 2) are 

shown in Table 2 with Wyoming’s proposed BART limit.

19 Except for Dave Johnston units 1 and 2, there 

has been some significant NOx reduction since 2003 at these facilities through implementation of 

combustion NOx controls.

Cost Estimating

The cost estimates are reflective of 2013 dollars, are summarized in the following sections of 

this report and are detailed in two Microsoft Excel workbooks attached to this report:

• WY_EGU BART RP costs_20131028

 19 WY Regional Haze SIP, January 7, 2011, Attachment A
www.AndoverTechnology.com 9

• WY_EGU BART RP_Jim Bridger Costs_20131028

The first workbook includes cost estimates for all units except Jim Bridger and the second 

includes cost estimates for Jim Bridger.

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

Control Cost Manual,20 capital cost estimates do not include AFUDC or Owner’s Costs (beyond the 10% 

allowed for engineering and home office). 

Table 2. Reported emission rates and Wyoming proposed BART limits for affected EGUs

Facility Name Facility ID 

(ORISPL) Unit ID

Annual Heat 

Input, 

MMBtu

2001-03 avg.

Avg. NOx Rate (lb/MMBtu)

2001-

2003 2011 2012

2013 

avg 

Q1, Q2

Wyoming

Proposed 

BART limit

*

Dave Johnston 4158 BW41 9,618,309 0.4549 0.3864 0.408 0.3844 none

Dave Johnston 4158 BW42 9,810,184 0.4406 0.4273 0.4235 0.4146 none

Dave Johnston 4158 BW43 19,209,226 0.5116 0.2261 0.2113 0.2273 0.28

Dave Johnston 4158 BW44 27,687,905 0.3662 0.1413 0.1543 0.1323 0.15

Jim Bridger 8066 BW71 42,980,000 0.3921 0.1929 0.18 0.1853 0.26

Jim Bridger 8066 BW72 40,900,000 0.3705 0.1853 0.1868 0.1933 0.26

Jim Bridger 8066 BW73 42,170,000 0.3725 0.1977 0.1965 0.2027 0.26

Jim Bridger 8066 BW74 41,030,000 0.3964 0.1981 0.1936 0.2124 0.26

Laramie River 6204 1 46,814,433 0.2585 0.1843 0.1718 0.1660 0.23

Laramie River 6204 2 46,557,737 0.2703 0.1838 0.1893 0.2097 0.21

Laramie River 6204 3 47,765,529 0.2669 0.2174 0.1945 0.2073 0.21

Naughton 4162 1 13,787,157 0.5155 0.5892 0.3389 0.2176 0.26

Naughton 4162 2 16,616,431 0.5221 0.5641 0.2157 0.2305 0.26

Naughton 4162 3 24,856,366 0.3656 0.4333 0.3454 0.2861 0.07

Wyodak 6101 BW91 35,204,108 0.2622 0.2062 0.1906 0.1937 0.23

All historical emissions and heat input data were developed from Air Markets Program Data.

* either 12 month or 30 day rolling average, depending upon facility

For combustion controls, capital and operating costs were based upon what was in the 

Wyoming proposed SIP supporting attachments, when available. In the case of Dave Johnston 1 and 2, 

the IPM cost estimating algorithms were used for combustion control capital and operating costs and 

the CEPCI was used to escalate from 2007 dollars to 2010 dollars.

For SNCR, the capital cost was assumed to be $20/kW (except for LRS 1-3, as discussed later). 

Except where furnace temperature information suggested otherwise, regent consumption was 

determined using a chemical utilization factor of 0.25. After combustion controls, SNCR can typically 

achieve NOx reductions of 20% to 30%.21 NOx reduction with SNCR is known to be greater at higher 

 20 EPA. 2002. EPA Air Pollution Control Cost Manual (Sixth Edition). EPA/452/B-02-001, p 2-5 - 2-7 21 Institute of Clean Air Companies, February 2008, p. 9
www.AndoverTechnology.com 10

NOx emission rates than lower rates.22, 23 NOx reduction was estimated as 30% for initial NOx greater 

than 0.25 lb/MMBtu, 25% for NOx from 0.20 to 0.25 lb/MMBtu and 20% for NOx less than 0.20 

lb/MMBtu. 

For consumables, the following estimates were used:

• Urea - delivered price of about $450/ton for a 50% by weight aqueous solution 24 

• Ammonia - $785/ton - this is based upon Basin Electric Exhibits

• Power – varies by site, based upon FERC 1 data or previous company data

SCR Retrofit Issues

An SCR retrofit is a capital intensive project that can require substantial modifications to the 

plant. SCR retrofits typically require that:

• The SCR reactor be built elevated on structural steel outside, but adjacent to the boiler building 

• Ductwork be routed from the boiler to the SCR inlet and back from the SCR exit to the air 

preheater inlet

• Modification of existing boiler building to accommodate SCR ductwork

• SCR support steel will frequently impact equipment located below the SCR

• A fan is frequently added to overcome additional pressure drop from the SCR, which also 

requires modification to auxiliary electrical system and review of ductwork for pressure integrity

• Use of large cranes to lift large sections of the SCR ductwork into place, requiring space for such 

cranes

• In many cases SCRs are built in middle units for boilers in a side by side arrangement that limits 

access to the middle units. Middle units, therefore, tend to be more difficult to retrofit with 

SCR.

• Often there are major pieces of equipment in the way, such as retired chimneys, that require 

longer ductwork routing. Or, there may be other equipment that must be demolished to 

provide access for construction equipment. In other cases equipment, such as air preheaters, 

need to be relocated to allow sufficient space for ductwork to and from the SCR.

• Space for construction materials is needed.

The following section will provide brief examples of SCR retrofits to give an idea of the issues 

that are commonly experienced in SCR retrofits as well as some of the differences that might be 

experienced and how they might impact cost. In some cases the cost of the project was available, and is 

provided both in reported dollars as well as escalated to 2012 dollars using the CEPCI. It is reasonable to 

assume that these reported costs are “all in” costs that include AFUDC since they are reported by the 

utilities who typically include this cost.

 22 Hofmann, J., Sun, W., “Process for Nitrogen Oxides Reduction to Lowest Achievable Level”, US Patent 5,229,090, 

July 20, 1993, Figure 6 23 US EPA Control Cost Manual, Section 1.2.3 SNCR Performance Parameters 24 Email from Doug Kirk, Fuel Tech, 10/12/2012
www.AndoverTechnology.com 11

Figure 3a. Montour SCR 25

As an example, Figure 3a shows the SCR 

that was built for the Montour Station (Figure 2b) 

in 2001 at a cost of $215 million or $143/kW

($205/kW escalated to 2013 dollars using the 

CEPCI), which included new ID fans, dismantling 

the old ESPs and erecting new ESPs for both units, 

shown in Figure 3b.

26 It is clear from the figure 

that the SCR reactor is built on a support 

structure and the ductwork must pass through 

the boiler building. Since the SCR is commonly 

built outside of the boiler building, it is routine to 

have to route ductwork through the boiler 

building wall. Ductwork to the ESP and ID fan is 

also below the structure.

Figure 3b. Montour Plant

 25 Glaser, R., Licata, A., Robinson, R., “THE SCR RETROFIT AT THE MONTOUR STEAM ELECTRIC STATION”

http://www.babcockpower.com/pdf/RPI-TP-0169.pdf 26 http://pplweb.mediaroom.com/index.php?s=12270&item=16522

Montour SCRs

New Montour ESPs
www.AndoverTechnology.com 12

Figure 4 is a photo taken by ATP of the SCRs at TVA’s Widow’s Creek units 7 and 8 (~470 MW 

each) while on a tour of the plant. The SCRs were completed in 2003 and 2004 at costs of $66 million 

($140/kW and $196/kW in 2013 dollars) and $61 million ($130/kW and $167/kW in 2013 dollars) for 

units 7 and 8, respectively.27 It is clear that the ductwork must pass through the boiler wall and that 

SCRs are directly above other equipment, including fans and ductwork. A large support structure is built 

to support both SCR reactors. The support structure in this case is built to go beyond the equipment to 

avoid interference with the equipment that is below. Unit 8 does not have an ESP, while unit 7 does.

Figure 4. SCRs at TVA Widows Creek 7 and 8

Progress Energy Carolina’s Asheville 1 (on the right side of Figure 5) was equipped with an SCR 

that went into service in 2007 at a total project cost of $35.7 million ($197/kW or $212/kW in 2013

dollars). 28 The project required replacement of the air preheater as well as the ESP. 29

 27 Attorney General of North Carolina v. Tennessee Valley Authority, Defendant’s Response to Plaintiff’s 

Interrogatories, September 1, 2006

28 Annual NC Clean Smokestacks Act Compliance Report, March 30, 2006

Widows Creek 7 

and 8 SCRs
www.AndoverTechnology.com 13

Figure 5. Progress Energy’s Asheville Power Plant

At the time it was completed, Belews Creek was the world’s largest SCR system. The cost of the 

SCR system was $450 million30, or roughly $202/kW in 2003 ($285/kW in 2013 dollars). The Belews 

Creek plant, shown in Figures 6a and b required installing two SCR reactors per unit on each of the 

roughly 1100 MW boilers. This SCR retrofit included replacement of the air preheaters – from horizontal 

shaft to vertical shaft – and also included replacement of both ID and FD fans.

 29 Cisek, Steve, “Case Histories: Asheville Power Station’s Retrofit First to Meet North Carolina’s Clean Smokestacks 

Act”, Power Magazine, 9/1/2006 30 http://www.asheville.com/news/dukepoweremission.html

Asheville 1 SCR
www.AndoverTechnology.com 14

Figure 6a. Belews Creek Power Plant

Figure 6b. Belews Creek31

 31 Duke Energy’s photostream, http://www.flickr.com/photos/dukeenergy/tags/scr/

Belews Creek SCRs

Belews Creek SCRs
www.AndoverTechnology.com 15

Figure 7. Brayton Point Power Plant, Somerset, MA

Even with very congested sites it is 

possible to install SCRs. Middle unit

arrangements are also not an unusual challenge. 

At the Brayton Point plant, shown in Figure 7, 

which is especially challenging, because it is an 

extremely congested site with four boilers sideby-side on a small peninsula with very little space 

to locate a crane, a derrick crane was installed on 

top of unit 3’s boiler when building the unit 3 

SCR.32 The derrick crane (see Figures 8a and b) made it possible to erect the unit 3 SCR without the 

need for a very large crane or without the need to demolish other existing equipment to provide access. 

A “rubber tire” crane (as opposed to the very heavy lift tractor-tread cranes typically used for SCRs) that 

did not take up much room was used to put the derrick crane in place. It was also necessary to put the 

support steel through a building below the SCR.

 32 http://www.cranestodaymagazine.com/features/the-first-tower-builders/image/the-first-towerbuilders-1.html

Brayton Point Unit 

3 SCR

Location of derrick 

crane during SCR 

construction
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Figure 8a. The Derrick Crane at Brayton Point 33

Figure 8b. Use of the Derrick Crane at Brayton Point 34

 33 Used with permission: http://www.cranestodaymagazine.com/features/the-first-tower-builders/image/the-firsttower-builders-1.html 34 Wright, B., Erickson, C., Phillipo, M.,”Keys to Success: SCR Installations at Dominions Brayton Point Units 1 and 

3”, Electric Power, May 2008
www.AndoverTechnology.com 17

The Ghent 1 SCR is an example of where the SCR ductwork had to both penetrate the boiler 

wall, underneath the coal conveyors and conveyor rooms while also being installed above other 

equipment. Figure 9a shows a satellite image of Ghent 1 and Figure 9b is a diagram of the configuration.

Figure 9a. Ghent 1 and SCR

Figure 9b. Ghent 1 SCR reactor and ductwork35

As shown from these figures, it was 

necessary at Ghent unit 1 to erect the SCR above the 

ESP and other equipment and also route the 

ductwork through the boiler wall and underneath 

the coal conveyors, resulting in unusually long 

horizontal duct runs.

 35 Saunders, E., Chelvan, T., Erickson, C., Jasinski, M., “Selective Catalytic Reduction System Performance at LG&E 

Energy LLC’s Mill Creek and Ghent Generating Stations”, Presented at EPRI Workshop on Selective Catalytic 

Reduction, October 19-20, 2004, Pittsburgh, Pennsylvania

Ghent Unit 1 SCR

Coal Conveyors
www.AndoverTechnology.com 18

At the Southern Company Plant Bowen SCRs shown in Figure 10, the SCR support steel actually 

goes through the inlet plenum to the ESP. Southern Company installed a dummy section into the ESP 

where the support column passes through. It was also necessary to modify the existing boiler building 

to accommodate the SCR ductwork. 36, 37

Figure 10. Plant Bowen SCRs

DTE Monroe, shown in Figure 11, has four 

nearly 800 MW units built side by side. SCR is installed 

on three of the four units and DTE announced that they 

would install SCR on the fourth unit at a cost of $330 

million, or roughly $412/kW.38 In this case the SCR 

reactors must be elevated well off of the ground and be 

built above the existing ESP structure and ductwork. 

Access is limited by the adjacent units, a coal conveyor 

as well as buildings on the site. Access to the site is very

limited because it is surrounded by water.

 36 Southern Company, “SCR Operating Experience”, EPRI SCR Workshop, October 31, 2006 37 Healy, E., Wall, D., Paseur, K.,” Implementation of SCR at Southern Company”, EPRI SCR Workshop, April 18-21, 

2000

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

Bowen SCRs
www.AndoverTechnology.com 19

Figure 11. DTE Monroe

Side-by-side retrofits are not uncommon. It is even possible to retrofit nine units in a row, as 

was performed at TVA’s Kingston power plant shown in Figures 12a and b. In this case it was also 

necessary to relocate air preheaters and work within the limitations of the existing ductwork and retired 

chimneys. Kingston is definitely an unusual case of a side-by-side retrofit, but it demonstrates what can 

be done. The cost of these retrofits ranged from $136/kW to $240/kW (2013 dollars).

Monroe SCRs

Location of Planned 

SCR
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Figure 12a. Kingston Power plant.

Figure 12b. Kingston Power Plant SCR (photo by ATP while on site visit)

Kingston units 1-9 

SCRs
www.AndoverTechnology.com 21

Situations where site visits are essential to identify interferences are when equipment 

like air preheaters must be moved or replaced or spacing for ductwork is not available without 

other substantial modifications. End units and single units typically have better access but can 

be very difficult when equipment needs substantial modification, such as air preheater 

relocation. TVA’s Colbert 5 is an end unit and the SCR could even be constructed with 

supporting structure to the ground, but the interface with the boiler and air preheater 

ductwork was very difficult. Figure 13 shows the Colbert SCR and the tight spacing between the 

boiler house and the ESP. When adjusted for 2012 dollars, at $312/kW (2013 dollars) the 

Colbert 5 SCR was the most costly SCR for TVA when measured in $/kW.

Bull Run, shown in Figures 14a and b is a single unit that does appear to generally have 

good access for construction of the SCR, however, it was necessary to relocate the air preheater 

at Bull Run, which at $303/kW (adjusted to 2013 dollars) made it the second most expensive 

TVA SCR when measured in terms of $/kW.

Figure 13. Colbert Power Plant SCR

Colbert 5 SCR
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Figure 14a. Bull Run Power Plant SCR

Figure 14b. Bull Run Power Plant SCR (photo by ATP while on plant tour)

Bull Run SCR

Bull Run SCR
www.AndoverTechnology.com 23

Paradise 1, 2 and 3, shown in Figure 15, are a good example of contrasts in difficulty. Paradise 1 

and 2 do not have ESPs (PM is captured in the scrubber), and therefore had ample room to install the 

SCR easily. The cost, escalated to 2013 dollars was $102/kW for unit 1 and $140/kW for unit 2. As 

expected for an inside unit, unit 2 was more expensive than unit 1 although the boilers and equipment 

are quite similar. Unit 3, with an ESP, entailed a more complex retrofit than either units 1 or 2, and cost 

$179/kW escalated to 2013 dollars.

Figure 15. Paradise Power Plant

TVA has a large fleet of SCRs. A summary of the cost for their SCRs are shown in Table 3. As 

shown, there is a wide range of costs because there is also a wide range of difficulties. In this case the 

most expensive SCR cost over $300/kW (escalated to 2013 dollars) because of the difficulty in making 

the duct connections between the SCR, the boiler and the air preheater. The least expensive SCR had 

the advantage of not having an ESP and a significant amount of open area between the boiler and 

scrubber.

Therefore, there are a number of factors that need to be considered when determining the 

difficulty of a retrofit, but a number of situations – such as routing boiler ductwork through boiler 

buildings, building the SCR on an above ground structure while trying to minimize the impact to 

equipment below, addition of more fan capacity, and retrofitting side-by-side units are very common 

issues (although side-by-side situations like Kingston are rare). Other factors that may vary from one

Paradise 1 & 2 SCRs

Paradise 3 SCR
www.AndoverTechnology.com 24

unit to another include the need to relocate large pieces of equipment, the access to the site, complex 

duct arrangements, the access for construction equipment near the boiler, equipment that may 

interfere with construction but is not going to be relocated (like a retired chimney), etc. These other 

factors are most often what determine if a retrofit will be significantly more expensive than normal. All 

of these factors were considered in developing retrofit difficulty factors.

Table 3. SCR costs for TVA coal power plants

Plant Unit SCR cost

In 

service

Capacity 

(net MW) $/kW $/kW (2013)

Allen

1 $30,500,000 2003 245 $124 $175

2 $28,800,000 2002 245 $118 $168

3 $50,000,000 2002 245 $204 $291

Bull Run 1 $210,000,000 2004 881 $238 $303

Colbert 5 $102,000,000 2003 459 $222 $312

Cumberland 1 $165,000,000 2003 1232 $134 $188

2 $159,000,000 2004 1233 $129 $164

Kingston

1 $25,250,000 2004 134 $188 $240

2 $25,250,000 2004 134 $188 $240

3 $25,250,000 2004 134 $188 $240

4 $25,250,000 2004 134 $188 $240

5 $28,000,000 2005 175 $160 $193

6 $28,000,000 2005 175 $160 $193

7 $28,000,000 2004 175 $160 $203

8 $28,000,000 2004 175 $160 $203

9 $21,000,000 2006 175 $120 $136

Paradise

1 $44,000,000 2001 616 $71 $102

2 $59,000,000 2000 602 $98 $140

3 $124,500,000 2003 977 $127 $179

Widows 

Creek

7 $65,900,000 2003 473 $139 $196

8 $61,000,000 2004 464 $131 $167

Average $155 $204

Median $160 $193

Minimum $71 $102

Maximum $238 $312

• SCR Cost and In service date from Defendant's Response to Plaintiff's Interrogatory #8, 

North Carolina v. TVA, Filed with US District Court, Asheville, NC, September 1, 2006.

• Cost escalation to 2013 dollars using the CEPCI. Using June 2013 CEPCI of 564.9 as 

published in September 2013 Chemical Engineering magazine
www.AndoverTechnology.com 25

SCR Cost Estimates from Basin Electric and PacifiCorp

PacifiCorp and Basin Electric provided SCR cost estimates for the following units:

• Dave Johnston 3

• Naughton units 1 and 2

• Laramie River 1-3

As demonstrated in Table 1, the cost estimates provided by these companies were at the 

extreme end of what has been experienced historically, or in some cases well above historical costs. As 

a result, the cost estimates are definitely very conservative and include substantial built-in contingency.

In all three 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

Although the Control Cost Manual (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 

Wyoming. According to the Department of Energy’s National Energy Technology Laboratory,

39

“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 was commercially available but was only 

emerging in application on coal fired utility boilers in the United States, According to a study by 

Cichanowicz, 40 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 about ten times to 

about 130,000 MW of coal capacity (over 40% of all coal capacity) and 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 Powder River Basin coals, which are 

very well understood SCR applications, 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.

 39 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. 40 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
www.AndoverTechnology.com 26

Because the cost estimates developed for PacifiCorp and Basin Electric are already very 

conservative and based upon detailed estimates of the labor and materials to build the SCR, a 15% 

project contingency is excessive. 

According to the 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 CCM were adapted from the American Association of 

Cost Engineers, or AACE (CCM Section 1, Chapter 2, p 2-5). AACE 16R-9041 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, 42 “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-9743 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 and Basin Electric in their comments, with hundreds of line items and thousands of 

input parameters and use of cost estimates from vendors, is clearly a far more detailed estimate that 

leaves out very little, if any, project scope that would fall into a Class 1 or 2.

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:

• 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 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, 

 41 AACE Recommended Practice, AACE 16R-90; www.aacei.org/non/rps/18R-90.pdf 42 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. 43 AACE Recommended Practice, AACE 16R-87; www.aacei.org/non/rps/18R-97.pdf
www.AndoverTechnology.com 27

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 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 Basin Electric and 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 was 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 lighting, 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 from Babcock & Wilcox (for PacifiCorp) and Sargent & Lundy (Basin Electric) 

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.

With regard to Laramie River Station, the itemized cost estimate in the Appendices to Exhibit 14 

from Basin Electric includes items that are normally incorporated into the General Facilities cost, while 

Sargent & Lundy took an additional provision for General Facilities (Exhibit 14 at page 31). The itemized 

cost estimate by Sargent & Lundy in the Appendices to Exhibit 14, however, includes the cost of many 

items that would normally fall under the category of General Facilities. This includes the cost of roads 

and a parking area ($930,226 at page 2 of SCR estimate), eye wash stations (page 3), a pre-engineered 

building for the construction warehouse ($780,000 page 8), fire protection systems (page 16), gratings, 

handrails, ladders (page 22). As a result, Sargent & Lundy double counts for General Facilities by having 

these costs accounted for in the itemized direct capital cost as well as in its Indirect Capital costs.

The cost estimate by Babcock & Wilcox for SCR on Dave Johnston unit 3 and Naughton units 

1 and 2 includes items like potable water systems, fire protection, service water, other assorted 

non-process auxiliaries as well as roads, fences, etc. which would fall into the category of General 

Facilities. Therefore, there is no need to add additional 5% for General Facilities.
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4. AFUDC

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

allowed.

5. Other items

There are a number of other items that were in the estimates provided by Basin Electric or 

PacifiCorp that have not been included in the capital costs. An example of this is additional overtime 

costs in Basin Electric’s estimate that appeared excessive in light of assumed labor rates that were 

already high when compared to published labor rates for construction trades. Another was excessive 

fees for the Contractor, amounting to 14%, that were reduced to a value of 10% that is consistent with 

what is used in the IPM. Because these costs were not supported by the information provided by Basin 

Electric, they were not allowed or were reduced.
www.AndoverTechnology.com 29

Dave Johnston, Units 1-4

An overhead view of Dave Johnston plant is shown in Figure 16. Dave Johnson 1 and 2 do not 

have NOx controls. Units 3 and 4 are equipped with combustion NOx controls and no post-combustion 

controls. 

Units 1 and 2 are dry bottom wall fired units and combustion control retrofits on such units are 

relatively routine. For units 1 and 2 EPA estimated emission rates are 0.20 lb/MMBtu (annual average) 

in the proposal in the Federal Register, and this is reasonable for LNBs with OFA (about 55% NOx 

reduction). For units 3 and 4, Wyoming’s analysis estimated an emission rate of 0.28 lb/MMBtu and 

0.15 lb/MMBtu (30-day average) with LNB and OFA for units 3 and 4, respectively.

44 Units 3 and 4 have 

already installed combustion controls as reflected in 2011 annual average NOx emission rates of 0.23 

lb/MMBtu and 0.14 lb/MMBtu, respectively.

Figure 16. Dave Johnston Power Plant

Retrofit costs

Retrofit costs for combustion controls and SNCR are expected to be consistent with other similar 

units. Retrofit costs for combustion controls are based upon company estimates for Units 3 and 4. 

 44 Wyoming Regional Haze SIP, Jan 7, 2011, Attachment A
www.AndoverTechnology.com 30

However, since the company did not provide costs for Units 1 and 2, IPM cost estimates were used. For 

SNCR a presumed capital cost of $20/kW is assumed.45

It was previously determined that post-combustion NOx controls, including SCR, are feasible, 

but they were not selected in Wyoming’s proposal as BART due to cost.44 Based upon the close 

proximity of the boilers and associated equipment to one another, decommissioned chimneys that will 

limit access and ability to move a crane, the coal pile and coal conveyors that also limits access to the 

area of the units where construction would occur, the office building that is adjacent to unit 1 and limits 

access, and the unit 4 scrubber, retrofit of an SCR on Units 1-4 would likely entail a significantly higher 

than average retrofit cost. Unit 4 probably has the best access of all of the units because there may be 

some space between the boiler and the scrubber, but it is difficult to say for sure from the image and 

therefore a conservatively high retrofit difficulty was used for unit 4 that is consistent with the other 

units. 

Based upon the aforementioned site issues the estimates of capital cost shown in Tables 3a (20 

year life) and 3b (9 years life for DJ3) are, in the case of DJ 1, 2, and 4, adjusted for retrofit difficulty 

using subjective factors that are integrated into the IPM cost estimating algorithms and a retrofit 

difficulty factor of 1.5 is assumed for all units. PacifiCorp provided an estimate of the cost of SCR for 

DJ3, and ATP has accepted that with a number of exceptions. When adjusting for items that are 

duplicative in cost (Project and Process Contingencies, General Facilities), the estimate using the cost 

provided by PacifCorp produces a very similar result as the cost that results from the IPM model. 

It is unclear why in the estimate developed by B&W that the horizontal ductwork to the SCR 

reactor (shown in Figures 17a and b) is as long as it is. There are no apparent obstructions in the 

drawings provided by Pacificorp or in the satellite photo that make such a long horizontal duct run 

necessary. The length of this duct run locates the SCR reactor above the retired chimney, which makes 

demolition of the chimney necessary. It appears that a shorter horizontal duct run and perhaps a 

change in the width and depth of the SCR reactor would reduce the cost of ductwork and might also 

make it possible to avoid demolition of the chimney. These effects might reduce the cost from what is 

estimated by Babcock & Wilcox.

Because combustion controls were placed in service around 2010, a life of 17 years is used for 

the combustion controls and 9 years for post-combustion controls in the shorter life case. Costs are 

shown for:

• Combustion Controls alone

• SNCR alone but after installation of combustion controls

• SCR alone but after installation of combustion controls

• Combustion controls in combination with SNCR

• Combustion controls in combination with SCR

 45 Based upon input from technology suppliers it was determined that $20/kW is a reasonable and conservative estimate of 

capital cost, and therefore this is used in lieu of the estimates used for IPM that are relied on by Wyoming in their SIP 

evaluation. See discussion beginning on page 3 of this report.
www.AndoverTechnology.com 31

Figure 17a. Drawing of SCR at Dave Johnston 3 – side view46

Figure 17b. Drawing of SCR at Dave Johnston 3 – top view46

 46 Babcock & Wilcox, Selective Catalytic Reduction Systems Naughton Units 1 and 2 and Dave Johnston Unit 3 

Budgetary Cost Estimate, August 19, 2013
www.AndoverTechnology.com 32

Table 3a. Dave Johnston Estimated Control Costs

DJ 1 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $95 $20 $422 $115 $517

Control Efficiency 56% 25% 75% 67% 89%

Uncontrolled Rate

NOx Rate (lb/hr) 536 236 236 536 536

NOx Rate (lb/MMBtu) 0.45 0.20 0.20 0.45 0.45

NOx (TPY) 2188 962 962 2188 2188

Controlled Rate

NOx Rate (lb/hr) 236 177 59 176.82 58.94

NOx Rate (lb/MMBtu) 0.20 0.15 0.05 0.15 0.05

NOx (TPY) 962 721 240 721.37 240.46

Tons/Year Removed 1226 240 721 1466.31 1947.23

Total Cost/year $1,214,000 $882,430 $5,594,374 $2,096,430 $6,808,374

$/Ton $990 $3,670 $7,755 $1,430 $3,496

$/ton Incremental $9,798 $3,670 $9,798

DJ 2 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $115 $20 $422 $135 $537

Control Efficiency 55% 25% 75% 66% 89%

Uncontrolled Rate

NOx Rate (lb/hr) 519 236 236 519 519

NOx Rate (lb/MMBtu) 0.44 0.20 0.20 0.44 0.44

NOx (TPY) 2161 981 981 2,161 2,161

Controlled Rate

NOx Rate (lb/hr) 236 177 59 177 59

NOx Rate (lb/MMBtu) 0.20 0.15 0.05 0.15 0.05

NOx (TPY) 981 736 245 736 245

Tons/Year Removed 1180 245 736 1,425 1,916

Total Cost/year $1,441,146 $893,877 $5,596,824 $2,335,022 $7,037,969

$/Ton $1,221 $3,645 $7,607 $1,638 $3,673

$/ton Incremental $9,588 $3,645 $9,588
www.AndoverTechnology.com 33

Table 3a. Dave Johnston Estimated Control Costs

DJ 3 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $73 $20 $368 $93 $440

Control Efficiency 58% 25% 77% 68% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1249 528 528 1249 1249

NOx Rate (lb/MMBtu) 0.51 0.22 0.22 0.51 0.51

NOx (TPY) 4913 2077 2077 4,913 4,913

Controlled Rate

NOx Rate (lb/hr) 528 396 122 396 122

NOx Rate (lb/MMBtu) 0.22 0.16 0.05 0.16 0.05

NOx (TPY) 2077 1558 480 1,558 480

Tons/Year Removed 2837 519 1597 3,356 4,433

Total Cost/year $1,699,807 $1,810,782 $9,980,337 $3,510,589 $11,680,144

$/Ton $599 $3,488 $6,251 $1,046 $2,635

$/ton Incremental $7,583 $3,488 $7,583

DJ 4 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $22 $20 $338 $42 $360

Control Efficiency 61% 20% 65% 69% 86%

Uncontrolled Rate

NOx Rate (lb/hr) 1325 511 511 1325 1325

NOx Rate (lb/MMBtu) 0.37 0.14 0.14 0.37 0.37

NOx (TPY) 5070 1956 1956 5,070 5,070

Controlled Rate

NOx Rate (lb/hr) 511 409 181 409 181

NOx Rate (lb/MMBtu) 0.14 0.11 0.05 0.11 0.05

NOx (TPY) 1956 1565 692 1,565 692

Tons/Year Removed 3114 391 1264 3,505 4,377

Total Cost/year $767,342 $1,774,258 $13,391,557 $2,541,600 $14,158,899

$/Ton $246 $4,535 $10,595 $725 $3,235

$/ton Incremental $13,312 $4,535 $13,312
www.AndoverTechnology.com 34

Table 3b. Dave Johnston Estimated Control Costs for 9 year life for SNCR and SCR and a 17 year life 

for combustion controls

DJ 3 Cost of controls 

Combustion Control

(CC) (already installed) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $73 $20 $368 $93 $440

Control Efficiency 58% 25% 77% 68% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1249 528 528 1249 1249

NOx Rate (lb/MMBtu) 0.51 0.22 0.22 0.51 0.51

NOx (TPY) 4913 2077 2077 4,913 4,913

Controlled Rate

NOx Rate (lb/hr) 528 396 122 396 122

NOx Rate (lb/MMBtu) 0.22 0.16 0.05 0.16 0.05

NOx (TPY) 2077 1558 480 1,558 480

Tons/Year Removed 2837 519 1597 3,356 4,433

Total Cost/year $1,828,137 $2,070,793 $14,762,870 $3,898,930 $16,591,006

$/Ton $644 $3,988 $9,247 $1,162 $3,742

$/ton Incremental $11,781 $3,988 $11,781
www.AndoverTechnology.com 35

Jim Bridger, Units 1-4

An overhead view of Jim Bridger plant is shown in Figure 18. All four units are tangentially fired 

and are currently equipped with combustion controls to reduce NOx emissions. Annual emission rates 

with combustion controls are assumed to be the lesser of the 2011 or 2012 annual average emission 

rate.

Retrofit costs

Retrofit costs for combustion controls are based upon company estimates. Retrofit costs for 

SNCR are expected to be consistent with other similar units and a presumed capital cost of $20/kW is 

assumed.47

It was previously determined that post-combustion NOx controls, including SCR, are feasible, 

but they were not selected in Wyoming’s proposal as BART due to cost.48 The estimates of SCR capital 

cost made here are adjusted for retrofit difficulty using subjective factors that are integrated into the 

IPM cost estimating algorithms. Based upon the satellite photo, the SCR reactors would likely be 

installed above the ESPs and ductwork routed to the boiler. The boilers do not appear to be unusually 

constrained from the perspective of installing SCR ductwork; however, access for construction 

equipment will be much more difficult to achieve for the two middle units. The scrubbers and 

associated piping will limit access somewhat. Unit 4 access will be limited somewhat by the coal 

conveyor and because it’s scrubber takes up more room than the other scrubbers. For this reason a 

retrofit difficulty factor of 1.5 is assumed for the middle units and 1.25 for units 1 and 4.

Table 4 shows the estimated costs of control for each of the Jim Bridger units. Costs are shown 

for:

• Combustion Controls alone

• SNCR alone but after installation of combustion controls

• SCR alone but after installation of combustion controls

• Combustion controls in combination with SNCR

• Combustion controls in combination with SCR

 47 Based upon input from technology suppliers it was determined that $20/kW is a reasonable and conservative 

estimate of capital cost, and therefore this is used in lieu of the estimates used for IPM that are relied on 

by Wyoming in their SIP evaluation. See discussion on page 2 of this report. 48 Wyoming Department of Environmental Quality on Jim Bridger Power Plant AP-6040 BART Application Analysis, 

May 28, 2009
www.AndoverTechnology.com 36

Figure 18. Jim Bridger Power Plant
www.AndoverTechnology.com 37

Table 4. Jim Bridger Estimated Control Costs

JB 1 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $278 $39 $297

Control Efficiency 54% 20% 72% 63% 87%

Uncontrolled Rate

NOx Rate (lb/hr) 2175 998 998 2175 2175

NOx Rate (lb/MMBtu) 0.39 0.18 0.18 0.39 0.39

NOx (TPY) 8426 3868 3868 8426 8426

Controlled Rate

NOx Rate (lb/hr) 998 799 277 798.61 277.29

NOx Rate (lb/MMBtu) 0.18 0.14 0.05 0.14 0.05

NOx (TPY) 3868 3094 1074 3094.39 1074.44

Tons/Year Removed 4558 774 2794 5332.02 7351.97

Total Cost/year $1,167,297 $3,162,755 $18,204,809 $4,330,052 $19,372,105

$/Ton $256 $4,088 $6,517 $812 $2,635

$/ton Incremental $7,447 $4,088 $7,447

JB 2 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $330 $39 $350

Control Efficiency 50% 20% 73% 60% 87%

Uncontrolled Rate

NOx Rate (lb/hr) 2035 1018 1018 2035 2035

NOx Rate (lb/MMBtu) 0.37 0.19 0.19 0.37 0.37

NOx (TPY) 7577 3789 3789 7,577 7,577

Controlled Rate

NOx Rate (lb/hr) 1018 814 275 814 275

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 3789 3031 1022 3,031 1,022

Tons/Year Removed 3787 758 2767 4,545 6,554

Total Cost/year $1,167,297 $3,123,887 $21,140,195 $4,291,184 $22,307,492

$/Ton $308 $4,122 $7,641 $944 $3,403

$/ton Incremental $8,968 $4,122 $8,968
www.AndoverTechnology.com 38

Table 4. Jim Bridger Estimated Control Costs

JB 3 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $333 $39 $353

Control Efficiency 47% 20% 75% 58% 87%

Uncontrolled Rate

NOx Rate (lb/hr) 2056 1085 1085 2056 2056

NOx Rate (lb/MMBtu) 0.37 0.20 0.20 0.37 0.37

NOx (TPY) 7853 4143 4143 7,853 7,853

Controlled Rate

NOx Rate (lb/hr) 1085 868 276 868 276

NOx Rate (lb/MMBtu) 0.20 0.16 0.05 0.16 0.05

NOx (TPY) 4143 3314 1054 3,314 1,054

Tons/Year Removed 3710 829 3089 4,539 6,799

Total Cost/year $1,167,297 $3,291,479 $21,406,623 $4,458,776 $22,573,920

$/Ton $315 $3,972 $6,931 $982 $3,320

$/ton Incremental $8,015 $3,972 $8,015

JB 4 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $280 $39 $299

Control Efficiency 51% 20% 74% 61% 87%

Uncontrolled Rate

NOx Rate (lb/hr) 2200 1074 1074 2200 2200

NOx Rate (lb/MMBtu) 0.40 0.19 0.19 0.40 0.40

NOx (TPY) 8133 3972 3972 8,133 8,133

Controlled Rate

NOx Rate (lb/hr) 1074 859 277 859 277

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 3972 3178 1026 3,178 1,026

Tons/Year Removed 4161 794 2946 4,956 7,108

Total Cost/year $1,167,297 $3,205,160 $18,327,121 $4,372,457 $19,494,417

$/Ton $281 $4,035 $6,220 $882 $2,743

$/ton Incremental $7,027 $4,035 $7,027
www.AndoverTechnology.com 39

Laramie River Units 1-3

The Laramie River plant has three roughly 570 MW units. All are dry bottom wall fired boilers 

and currently are equipped with LNBs and OFA and averaged under 0.20 lb/MMBtu in 2012. 

Retrofit Costs

Data provided by Basin Electric indicated a very high furnace exit temperature. As a result, it is 

anticipated that a more costly injection system was likely and Basin Electric’s estimate of SNCR capital 

cost was accepted. In addition, in light of the high temperature, a reagent utilization rate of 12% was 

assumed, per information from Basin Electric.

The plant is shown in Figures 19a and 19 b. These figures show a less constrained site than Dave 

Johnston, with good access to both units 1 and 3. The coal conveyor is clearly visible and will be an 

obstruction for the unit 2 SCR. As a result, retrofit difficulty of installing SCR is expected to be average, 

except possibly for unit 2 which is located between units 1 and 3. Access of a crane will be somewhat 

more challenging for unit 2 and when the IPM algorithms were used an SCR retrofit difficulty of 1.2 is 

assumed for estimating SCR capital cost. In all cases the SCR reactor is likely to be installed above the 

ESP ductwork. 

Basin Electric’s estimated cost of constructing the SCRs was accepted, but without some items 

such as additional overtime, project contingency, process contingency and general facilities. The 

detailed cost estimate by Sargent & Lundy for Basin Electric already included the costs that would fall 

into those categories, and it would therefore be double counting to additionally include those costs. 

Also, the assumed labour rates for construction labour were well in excess of published rates, suggesting 

that allowances for overtime were already incorporated into the labour rates.

Information from Basin Electric (see Figures 20a and b) demonstrates that SCR ductwork and 

configuration are typical arrangements, without the need for any unusually long ductwork routing or 

relocation of major equipment. The modifications necessary to install the SCR are modifications that are 

routinely necessary for SCR retrofits.

The Wyoming analysis indicated that NOx should be reduced to around 0.18±0.02 lb/MMBtu 

with LNB and OFA and suggested a 30-day rolling average rate of 0.23 lb/MMBtu. 49 Recent emission 

data is shown in Table 2 and confirm that these rates are possible. Wyoming had previously suggested

that addition of SNCR would reduce NOx to 0.12 lb/MMBtu (assumedly on a 30-day rolling average 

basis). This is greater NOx reduction from SNCR than expected and is inconsistent with other 

experience. Fuel Tech, the leading supplier of SNCR, was contacted and confirmed that an emission 

reduction of about 20% is expected from SNCR at these NOx levels, which suggests an annual emission 

rate close to 0.15 lb/MMBtu with SNCR from an annual rate of about 0.19 lb/MMBtu without SNCR. 50

The cost analysis of Table 5 shows slightly different costs for the three Laramie River units, 

although they are similar boilers. This is in part due to the units having slightly different starting NOx 

 49 DEPARTMENT OF ENVIRONMENTAL QUALITY, AIR QUALITY DIVISION, BART Application Analysis, AP-6047, Laramie River 

Station, May 28, 2009, pages 7 and 8 50 Email from Fuel Tech, October 15, 2012
www.AndoverTechnology.com 40

levels, which affect the costs. In addition, according to NEEDS data, unit 1 has slightly lower capacity 

than units 2 and 3 (565 MW versus 570 MW). NEEDS also indicated slightly different heat rates for the 

units, which impact capacity factors and tons of NOx emitted. Costs are shown for:

• Combustion Controls alone

• SNCR alone but after installation of combustion controls

• SCR alone but after installation of combustion controls

• Combustion controls in combination with SNCR

• Combustion controls in combination with SCR
www.AndoverTechnology.com 41

Figure 19a. Laramie River Units 1-3

Figure 19b. Laramie River Units 1-3
www.AndoverTechnology.com 42

Figure 20a Laramie River SCR – Side View of SCR 51

Figure 20b. Laramie River SCR – top view51

 51 Appendices to Exhibit 14 of Basin Electric Comments
www.AndoverTechnology.com 43

Table 5. Laramie River Estimated Control Costs

LR 1 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $37 $30 $282 $67 $319

Control Efficiency 26% 20% 74% 41% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1652 1227 1227 1652 1652

NOx Rate (lb/MMBtu) 0.26 0.19 0.19 0.26 0.26

NOx (TPY) 6051 4495 4495 6,051 6,051

Controlled Rate

NOx Rate (lb/hr) 1227 982 320 982 320

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 4495 3596 1170 3,596 1,170

Tons/Year Removed 1556 899 3324 2,455 4,880

Total Cost/year $2,268,806 $6,286,091 $19,501,329 $8,554,896 $21,770,134

$/Ton $1,458 $6,993 $5,866 $3,485 $4,461

$/ton Incremental $5,449 $6,993 $5,449

LR 2 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $37 $30 $294 $67 $331

Control Efficiency 29% 20% 74% 43% 82%

Uncontrolled Rate

NOx Rate (lb/hr) 1688 1199 1199 1688 1688

NOx Rate (lb/MMBtu) 0.27 0.19 0.19 0.27 0.27

NOx (TPY) 6293 4470 4470 6,293 6,293

Controlled Rate

NOx Rate (lb/hr) 1199 959 312 959 312

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 4470 3576 1164 3,576 1,164

Tons/Year Removed 1823 894 3306 2,717 5,129

Total Cost/year $2,268,806 $6,262,825 $20,422,662 $8,531,631 $22,691,467

$/Ton $1,244 $7,006 $6,178 $3,140 $4,424

$/ton Incremental $5,871 $7,006 $5,871
www.AndoverTechnology.com 44

Table 5. Laramie River Estimated Control Costs

LR 3 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $37 $30 $294 $67 $331

Control Efficiency 28% 20% 74% 42% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1778 1279 1279 1778 1778

NOx Rate (lb/MMBtu) 0.27 0.19 0.19 0.27 0.27

NOx (TPY) 6375 4586 4586 6,375 6,375

Controlled Rate

NOx Rate (lb/hr) 1279 1023 333 1023 333

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 4586 3669 1194 3,669 1,194

Tons/Year Removed 1789 917 3392 2,706 5,181

Total Cost/year $2,268,806 $6,375,033 $20,398,176 $8,643,839 $22,666,982

$/Ton $1,268 $6,951 $6,014 $3,194 $4,375

$/ton Incremental $5,667 $6,951 $5,667
www.AndoverTechnology.com 45

Naughton Units 1-3

The Naughton units 1, 2 and 3 are 160 MW, 210 MW and 330 MW, respectively. All are 

tangentially fired and have recently installed combustion controls. It is assumed that Naughton Units 1 

and 2 will achieve similar rates with controls, about 0.21 lb/MMBtu annual average. It is assumed that 

Naughton Unit 3 will achieve 0.33 lb/MMBtu annual average since that is 10% lower than the 0.37 

lb/MMBtu presumed 30 day average by Wyoming, thereby accounting for the longer averaging period.

Retrofit costs

Naughton Units 1-3 are shown in Figure 21. Like most of the other plants, SNCR costs are 

assumed to be $20/kW. 

Babcock & Wilcox provided cost estimates for the Naughton unit 1 & 2 SCRs. Babcock & 

Wilcox’s estimate assumed that it would be necessary to demolish stacks that will be abandoned after a 

planned scrubber installation and they also determined that additional fan capacity was not necessary. 

Babcock & Wilcox also assumed a complex support structure would be needed, which adds cost. 

Babcock and Wilcox also stated that units 1 and 2 are slightly offset which makes it impractical to build a 

common support structure for the SCR reactors; however, as shown in Figures 22, 23, and 24, Babcock & 

Wilcox has used a longer horizontal duct run on the unit 1 SCR which places the unit 1 and unit 2 SCR 

reactors side-by-side so that a common support structure is likely to be possible, offering some potential 

savings from what they have estimated. Alternatively, a shorter horizontal duct run on unit 1 may make 

it possible to avoid demolition of the unit 1 chimney that will be abandoned. When using the IPM 

algorithm a retrofit difficulty factor of 1.3 is assumed. This was based upon the fact that it appeared to 

be a less congested site than Dave Johnston, but there were potential challenges, such as the chimneys, 

that could result in longer duct runs or additional demolition.

For unit 3 it is also unclear if there is enough space to install the SCR reactor on the same side of 

the chimney as the boiler, which, means that demolition of that chimney may be needed. There 

appears to be access for construction equipment, such as a crane, in the area east of the plant (the 

upper part of the photo) and to the north of unit 3. In estimating the cost of the SCR for unit 3, retrofit 

difficulty is above average because more lengthy duct runs or demolition of the chimney are likely 

needed, and an assumed retrofit difficulty factor of 1.3 is assumed for unit 3.

Results of cost calculations for a 20 year life are shown in Table 6a and Table 6b for an 11 year 

life for units 1 and 2. Because combustion controls were placed in service around 2012, a life of 17 

years is used for the combustion controls and 11 years for post-combustion controls in the shorter life 

case. Costs are shown for:

• Combustion Controls alone

• SNCR alone but after installation of combustion controls

• SCR alone but after installation of combustion controls

• Combustion controls in combination with SNCR

• Combustion controls in combination with SCR
www.AndoverTechnology.com 46

Figure 21. Naughton Units 1-3

–
www.AndoverTechnology.com 47

Figure 22. Naughton unit 1 SCR – side view 52

Figure 23. Naughton unit 2 SCR side view52

 52 Babcock & Wilcox, Selective Catalytic Reduction Systems Naughton Units 1 and 2 and Dave Johnston Unit 3 

Budgetary Cost Estimate, August 19, 2013
www.AndoverTechnology.com 48

Figure 24. Naughton 1 (right) & 2 (left) SCRs, top view53

 53 Developed from Babcock & Wilcox, Selective Catalytic Reduction Systems Naughton Units 1 and 2 and Dave 

Johnston Unit 3 Budgetary Cost Estimate, August 19, 2013
www.AndoverTechnology.com 49

Table 6a. Naughton Estimated Control Costs

N 1 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $55 $20 $467 $75 $521

Control Efficiency 59% 25% 76% 69% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 895 366 366 895 895

NOx Rate (lb/MMBtu) 0.52 0.21 0.21 0.52 0.52

NOx (TPY) 3553 1453 1453 3553 3553

Controlled Rate

NOx Rate (lb/hr) 366 274 87 274 87

NOx Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05

NOx (TPY) 1453 1090 345 1090 345

Tons/Year Removed 2100 363 1109 2463 3209

Total Cost/year $932,466 $1,302,361 $9,042,150 $2,234,827 $9,974,616

$/Ton $444 $3,584 $8,155 $907 $3,109

$/ton Incremental $10,384 $3,584 $10,384

N 2 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $40 $20 $353 $60 $393

Control Efficiency 60% 25% 76% 70% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1174 474 474 1174 1174

NOx Rate (lb/MMBtu) 0.52 0.21 0.21 0.52 0.52

NOx (TPY) 4337 1752 1752 4337 4337

Controlled Rate

NOx Rate (lb/hr) 474 356 112 356 112

NOx Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05

NOx (TPY) 1752 1314 415 1314 415

Tons/Year Removed 2586 438 1336 3024 3922

Total Cost/year $883,900 $1,596,932 $9,178,850 $2,480,832 $10,062,750

$/Ton $342 $3,647 $6,869 $820 $2,566

$/ton Incremental $8,440 $3,647 $8,440
www.AndoverTechnology.com 50

Table 6a. Naughton Estimated Control Costs

N 3 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $3 $20 $322 $23 $325

Control Efficiency 10% 30% 85% 37% 86%

Uncontrolled Rate

NOx Rate (lb/hr) 1266 1142 1142 1266 1266

NOx Rate (lb/MMBtu) 0.37 0.33 0.33 0.37 0.37

NOx (TPY) 4544 4101 4101 4544 4544

Controlled Rate

NOx Rate (lb/hr) 800 173 800 173

NOx Rate (lb/MMBtu) 0.33 0.23 0.05 0.23 0.05

NOx (TPY) 4101 2871 621 2871 621

Tons/Year Removed 442 1230 3480 1673 3922

Total Cost/year $106,393 $3,745,984 $13,498,309 $3,852,377 $13,604,702

$/Ton $240 $3,045 $3,879 $2,303 $3,469

$/ton Incremental $4,335 $3,045 $4,335
www.AndoverTechnology.com 51

Table 6b. Naughton Estimated Control Costs for 11 year life for SNCR and SCR and 17 year life for 

combustion controls

N 1 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $55 $20 $353 $75 $407

Control Efficiency 59% 25% 76% 69% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 895 366 366 895 895

NOx Rate (lb/MMBtu) 0.52 0.21 0.21 0.52 0.52

NOx (TPY) 3553 1453 1453 3553 3553

Controlled Rate

NOx Rate (lb/hr) 366 274 87 274 87

NOx Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05

NOx (TPY) 1453 1090 345 1090 345

Tons/Year Removed 2100 363 1109 2463 3209

Total Cost/year $1,002,863 $1,427,046 $11,950,751 $2,429,910 $12,953,615

$/Ton $478 $3,927 $10,779 $986 $4,037

$/ton Incremental $14,118 $3,927 $14,118

N 2 Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $40 $20 $334 $60 $374

Control Efficiency 60% 25% 76% 70% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1174 474 474 1174 1174

NOx Rate (lb/MMBtu) 0.52 0.21 0.21 0.52 0.52

NOx (TPY) 4337 1752 1752 4337 4337

Controlled Rate

NOx Rate (lb/hr) 474 356 112 356 112

NOx Rate (lb/MMBtu) 0.21 0.16 0.05 0.16 0.05

NOx (TPY) 1752 1314 415 1314 415

Tons/Year Removed 2586 438 1336 3024 3922

Total Cost/year $950,631 $1,760,581 $12,069,960 $2,711,212 $13,020,591

$/Ton $368 $4,020 $9,033 $897 $3,320

$/ton Incremental $11,476 $4,020 $11,476
www.AndoverTechnology.com 52

Wyodak

Wyodak Power Plant is located on the Wyodak Energy Complex that includes the Wygen units 1-

3 and Neil Simpson units 1, 2. Wyodak is a 335 MW dry bottom wall-fired unit equipped with low NOx 

burners and overfire air. In 2011 the annual average NOx emission was under 0.21 lb/MMBtu and the 

average for the first nine months of 2012 was under 0.20 lb/MMBtu. Additional NOx controls would 

likely entail SNCR or SCR.

Retrofit costs

As with the other plants, SNCR is assumed to cost $20/kW to install.

In the event SCR were installed at the site, the SCR reactor would likely be located above the 

existing (but decommissioned) ESP shown between the boiler building and the chimney in Figure 25. 

There is ample room on the site for lay down of material. Location of a crane near the construction site 

appears to be possible; however, in every direction from the boiler there is a potential interference that 

might complicate crane location relative to the lay-down area. Therefore, the difficulty of this retrofit is 

probably average to perhaps above average. A conservative estimate of retrofit difficulty of 1.3 is 

assumed, although a closer examination of the site may show that a lower retrofit difficulty may be 

possible.

Table 7 shows the results of cost calculations. Costs are shown for:

• Combustion Controls alone

• SNCR alone but after installation of combustion controls

• SCR alone but after installation of combustion controls

• Combustion controls in combination with SNCR

• Combustion controls in combination with SCR
www.AndoverTechnology.com 53

Figure 25. Wyodak Power Plant
www.AndoverTechnology.com 54

Table 7. Wyodak Estimated Control Costs

Cost of controls

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $36 $20 $321 $56 $357

Control Efficiency 27% 20% 74% 41% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1060 775 775 1060 1060

NOx Rate (lb/MMBtu) 0.26 0.19 0.19 0.26 0.26

NOx (TPY) 4615 3376 3376 4,615 4,615

Controlled Rate

NOx Rate (lb/hr) 775 620 202 620 202

NOx Rate (lb/MMBtu) 0.19 0.15 0.05 0.15 0.05

NOx (TPY) 3376 2701 880 2,701 880

Tons/Year Removed 1239 675 2496 1,914 3,735

Total Cost/year $1,272,427 $2,454,146 $13,801,075 $3,726,573 $15,073,502

$/Ton $1,027 $3,635 $5,530 $1,947 $4,036

$/ton Incremental $6,233 $3,635 $6,233