www.AndoverTechnology.com 1

October 23, 2012

To: Doug Grano

Fm: Jim Staudt

Re: Review of Estimated Compliance Costs for Wyoming Electricity Generating Units (EGUs) 

Attachment: Microsoft Excel Workbook WY EGU BART_RP Costs_20121019.xlsx

On June 4, 2012 (77 FR 33022), EPA proposed the Wyoming Regional Haze Federal implementation plan. 

Below is Andover Technology Partners’ evaluation of the cost of nitrogen oxides NOx emission controls 

for particular power plants in Wyoming subject to EPA’s proposed rulemaking. These plants and units 

include:

• Dave Johnson, units 1-4

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

• Naughton units 1, 2 and 3

• Wyodak

Note that Dave Johnston Units 1-2 are not subject to Best Available Retrofit Technology (BART) 

requirements, but the cost of compliance for these units has been evaluated here under reasonable 

progress reguirements.

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: the 

lower of 2011 annual emission rate or the average of 2012 Q1 and Q2, or, where there is no available 

operating data with combustion controls, a projected emission rate. 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.

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

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

 1 EPA. 2002. EPA Air Pollution Control Cost Manual (Sixth Edition). EPA/452/B-02-001
www.AndoverTechnology.com 2

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 taxes, insurance and administrative costs, and the use of overnight cost2 for capital 

cost.

Combustion Controls

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

were used. If not, IPM models were used to estimate capital and operating costs of combustion 

controls.

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. Fixed and 

variable operating costs of combustion controls were estimated from IPM algorithms.

SNCR

For SNCR, capital cost is assumed to be $20/kW. 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 my personal 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

And, I have also published reports that describe the cost and application of technologies used for control 

of NOx, including SNCR.

9, 10

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

for Funds Used During Construction (AFUDC) 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 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 8 Ibid

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 
www.AndoverTechnology.com 3

Therefore, $20/kW provides a reasonable estimate for the capital cost of SNCR. Furthermore, due to 

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

component of cost.

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. It was not possible to evaluate all of the

relevant factors because detailed furnace characteristics were not available. 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. 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.

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

algorithms.

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) 

SCR

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 

 

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

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 30 to 50% 

over the base model. 12

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, 13, 14 Estimates were also compared against 

estimates provided by the facility owners (both December 2007 and March 2008 estimates for Dave 

Johnston, Naughton and Wyodak, and June 2008 for Laramie River). For Dave Johnston, Naughton and 

Wyodak units the estimated capital cost of SCR provided by the owners for the five units increased by 

roughly 60% between these two dates, and I did not see an explanation for the increase in cost.

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

(see workbook: WY EGU BART_RP Costs_20121019.xlsx)15

Plant Dave Johnston Naughton

Laramie 

River Wyodak

Unit BW43 BW44 1 2 3 1-3 BW91

Capacity, MW 220 330 160 210 330 565 335

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

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

4 month % increase 66% 46% 67% 63% 49% 60%

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

 

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

periods, including 2008-2010. Note that, as shown on Figure 2, all costs have been normalized to a 2008 

basis. In addition, these costs are on the same basis as those shown above (inclusive of owner’s costs, 

AFUDC, etc.). As shown, the Wyoming owner’s estimates in Table 1 for December 2007 were in the 

same range as the actuals reported by Cichanowicz for installations which occurred between 2008 and 

2010 ($125/kW to $450/kW), but the capital costs reported only four months later for Dave Johnston, 

Naughton and Wyodak (all owned by Pacificorp) were near or well above the highest costs (in $/kW) 

reported by Cichanowicz in the 2008-2010 period. The dramatic increase in estimated cost between 

December 2007 and March 2008 for the Pacificorp units and the stark inconsistency of the March 2008 

estimated costs with other industry data begs more explanation from the owners about their reported 

costs. The SCR cost estimate from Basin Electric for the Laramie River units was consistent with what 

industry had reported.

 12 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. 13 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 14 Cichanowicz, J. E., “CURRENT CAPITAL COST AND COST-EFFECTIVENESS OF POWER PLANT EMISSIONS CONTROL 

TECHNOLOGIES”, Prepared for Utility Air Regulatory Group, January 2010 15 This workbook is discussed in further detail in the Cost Estimating section of this memo
www.AndoverTechnology.com 5

Figure 2 also demonstrates two other points –

• The scatter in cost shows that SCR capital cost is a strong function of site conditions as well as 

capacity, and this is why a retrofit factor is important.

• SCR costs have increased significantly between 2000 and the 2008-2010 period.

Regarding the first point, the IPM documentation states that “Retrofit difficulties associated with an SCR 

may result in capital cost increases of 30 to 50% over the base model. “ 16 So, retrofit factors up to 1.5 

were used in my cost estimates.

Regarding the second point, this is supported by the increase in the Chemical Engineering Plant Cost 

Index (CEPCI) between 2000 and 2007, as shown in Figure 3. However, between 2006 and 2012 the 

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

peaked in August 2008 at 619.3. The July 2012 CEPCI, recently published in the October 2012 issue of 

Chemical Engineering, was reported to be 582.2 and is shown as the 2012 value on Figure 3. Therefore, 

the rapid escalation of cost that was experienced after 2003 and peaked in August 2008 has slowed 

down appreciably.

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

 16 Appendix 5-2A (SCR) of the IPM Base Case v.4.10 documentation, p 1. 17 Cichanowicz, January 2010
www.AndoverTechnology.com 6

Figure 3. Annual Chemical Engineering Plant Cost Index (CEPCI)

Chemical Engineering magazine

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 and 2012 year-to-date are shown in Table 2

with Wyoming’s proposed BART limit.

18 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. The most recent NOx reductions occurred at Naughton plant in 2012. For Naughton 1, 

Separated Overfire Air was installed in June, which is why the reduction in NOx is not yet reflected in the 

six months of data for 2012. It is assumed that Naughton 1 will achieve the same NOx emissions rate as 

Naughton 2 since they are both tangential furnaces, both have similar NOx emissions prior to the 

installation of controls and, according to the Wyoming BART proposed limits, are projected to have 

similar emission rates after the installation of controls. For Naughton 3, it is assumed that the annual 

average emission rate with combustion controls will be 0.33 lb/MMBtu – roughly 10% lower than the 

expected 30-day average with combustion controls in Wyoming’s proposed SIP.

Cost Estimating

The cost estimates summarized in the following sections of this memo are detailed in a Microsoft Excel 

workbook WY_EGU_BART_RP_Costs_20121019.xlsx that is an attachment to this memo. The details of 

the estimating methods are described in the workbook. Consistent with the EPA Control Cost Manual,19

 18 WY Regional Haze SIP, January 7, 2011, Attachment A 19 EPA. 2002. EPA Air Pollution Control Cost Manual (Sixth Edition). EPA/452/B-02-001, p 2-5 - 2-7

0%

10%

20%

30%

40%

50%

60%

300

350

400

450

500

550

600

2000200120022003200420052006200720082009201020112012

Percent change in CEPCI since 2000

CEPCI

Year

Chemical Engineering Plant

Cost Index (CEPCI)

CEPCI % growth from 2000
www.AndoverTechnology.com 7

capital cost estimates do not include AFUDC or Owner’s Costs. With regard to capital cost escalation, as 

demonstrated in Figure 3, the CEPCI has remained in a range of about 550 ± 50 since 2006. Since all of 

the capital cost estimates and algorithms that are utilized in this effort were developed since 2006, 

escalation has been modest, and was adjusted for in some cases.

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 YTD

Wyoming

Proposed 

BART limit *

Dave Johnston 4158 BW41 9,618,309 0.4549 0.3864 0.3934 none

Dave Johnston 4158 BW42 9,810,184 0.4406 0.4273 0.4328 none

Dave Johnston 4158 BW43 19,209,226 0.5116 0.2261 0.2162 0.28

Dave Johnston 4158 BW44 27,687,905 0.3662 0.1413 0.2039 0.15

Laramie River 6204 1 46,814,433 0.2585 0.1843 0.1930** 0.23

Laramie River 6204 2 46,557,737 0.2703 0.1838 0.1901 0.21

Laramie River 6204 3 47,765,529 0.2669 0.2174 0.1930 0.21

Naughton 4162 1 13,787,157 0.5155 0.5892 0.5551 0.26

Naughton 4162 2 16,616,431 0.5221 0.5641 0.2108 0.26

Naughton 4162 3 24,856,366 0.3656 0.4333 0.3984 0.07

Wyodak 6101 BW91 35,204,108 0.2622 0.2062 0.1918 0.23

All historical emissions and heat input data developed from Air Markets Program Data. For 2012 YTD for Laramie 

River and Wyodak nine months of data was available, for others only six months of data was available 

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

** April and May 2012 data was excluded for LR1 due to apparent shutdown and/or use of natural gas

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. 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%.20 NOx reduction with SNCR is known to be greater at higher NOx emission 

rates than lower rates.21 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, notably urea, there has been significant variability in cost, and current cost estimates 

were used (delivered price of about $650/ton).

22, 23 Unfortunately, the cost of urea has increased 

 20 Institute of Clean Air Companies, February 2008, p. 9 21 Hofmann, J., Sun, W., “Process for Nitrogen Oxides Reduction to Lowest Achievable Level”, US Patent 5,229,090, 

July 20, 1993, Figure 6 22 Email from Jennifer Zagorsky, Potash Corp. 10/15/2012 23 Email from Doug Kirk, Fuel Tech, 10/12/2012
www.AndoverTechnology.com 8

significantly, as indicated in Figure 4, an index that is indicative of the price of urea paid to producers 

(not including transport, etc.). As shown, producer prices have roughly doubled in the past three years. 

“Improvement” as used in the figure, means increasing prices for producers.

Figure 4. Profercy World Nitrogen Index.

www.fertilizerworks.com/html/market/profercy.pdf
www.AndoverTechnology.com 9

Dave Johnston, Units 1-4

An overhead view of Dave Johnston plant is shown in Figure 5. 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.

24 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.

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. 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.

25

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.

24 Based upon the close proximity of the 

boilers and associated equipment (including, decommissioned chimneys) to one another, and the coal 

pile, retrofit of an SCR on Units 1-3 would likely entail a significantly higher than average retrofit cost. 

There may be more space available near unit 4 for a retrofit of SCR, but this is unclear from the 

photograph. For these reasons, the estimates of capital cost shown in Table 3 are 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.

 24 Wyoming Regional Haze SIP, Jan 7, 2011, Attachment A 25 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 memo.
www.AndoverTechnology.com 10

Figure 5. Dave Johnston Power Plant
www.AndoverTechnology.com 11

Table 3. David Johnston Estimated Control Costs

DJ 1 Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $93 $113 $439

Control Efficiency 56% 67% 89%

Uncontrolled Rate

NOx Rate (lb/hr) 536 536 536

NOx Rate (lb/MMBtu) 0.45 0.45 0.45

NOx (TPY) 2188 2188 2188

Controlled Rate

NOx Rate (lb/hr) 236 176.82 58.94

NOx Rate (lb/MMBtu) 0.20 0.15 0.05

NOx (TPY) 962 721.37 240.46

Tons/Year Removed 1226 1466.31 1947.23

Total Cost/year $1,187,179 $2,338,102 $6,619,121

$/Ton $968 $1,595 $3,399

$/ton Incremental $4,786 $8,902

DJ 2 Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $93 $113 $439

Control Efficiency 55% 66% 89%

Uncontrolled Rate

NOx Rate (lb/hr) 519 519 519

NOx Rate (lb/MMBtu) 0.44 0.44 0.44

NOx (TPY) 2161 2,161 2,161

Controlled Rate

NOx Rate (lb/hr) 236 177 59

NOx Rate (lb/MMBtu) 0.20 0.15 0.05

NOx (TPY) 981 736 245

Tons/Year Removed 1180 1,425 1,916

Total Cost/year $1,188,797 $2,356,537 $6,637,642

$/Ton $1,007 $1,653 $3,464

$/ton Incremental $4,761 $8,728
www.AndoverTechnology.com 12

Table 3. David Johnston Estimated Control Costs

DJ 3 Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $73 $93 $378

Control Efficiency 58% 68% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1249 1249 1249

NOx Rate (lb/MMBtu) 0.51 0.51 0.51

NOx (TPY) 4913 4,913 4,913

Controlled Rate

NOx Rate (lb/hr) 528 396 122

NOx Rate (lb/MMBtu) 0.22 0.16 0.05

NOx (TPY) 2077 1,558 480

Tons/Year Removed 2837 3,356 4,433

Total Cost/year $1,699,807 $4,087,200 $11,708,335

$/Ton $599 $1,218 $2,641

$/ton Incremental $4,598 $7,074

DJ 4 Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $22 $42 $297

Control Efficiency 61% 69% 86%

Uncontrolled Rate

NOx Rate (lb/hr) 1325 1325 1325

NOx Rate (lb/MMBtu) 0.37 0.37 0.37

NOx (TPY) 5070 5,070 5,070

Controlled Rate

NOx Rate (lb/hr) 511 409 181

NOx Rate (lb/MMBtu) 0.14 0.11 0.05

NOx (TPY) 1956 1,565 692

Tons/Year Removed 3114 3,505 4,377

Total Cost/year $767,342 $3,000,528 $13,375,101

$/Ton $246 $856 $3,055

$/ton Incremental $5,708 $11,888
www.AndoverTechnology.com 13

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 through 

September. 

Retrofit Costs

For SNCR a presumed capital cost of $20/kW is assumed. SNCR does not require much space and 

retrofit difficulty does not vary much for SNCR.

The plant is shown in Figures 6a and b. These figures show a much less constrained site than Dave 

Johnston. 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 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.

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. 26 Actual emission levels at the 

plant for the first nine months of 2012 for all three units are about 0.19 lb/MMBtu, which is an 

indication of what is expected on an annual average basis. Units 1 and 2 had even lower annual 

average emission rates in 2011 at about 0.18 lb/MMBtu and Unit 3 was somewhat higher just under

0.22 lb/MMBtu, with the average of the three units combined at about 0.195 lb/MMBtu annual average. 

The Wyoming document also suggests 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. 27

The cost analysis of Table 4 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 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. Finally, a modestly higher SCR retrofit difficulty factor 

is assumed for unit 2 because access will be poorer than for units 1 or 3.

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

Station, May 28, 2009, pages 7 and 8 27 Email from Fuel Tech, October 15, 2012
www.AndoverTechnology.com 14

Figure 6a. Laramie River Units 1-3

Figure 6b. Laramie River Units 1-3
www.AndoverTechnology.com 15

Table 4. Laramie River Estimated Control Costs

LR 1 Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $37 $57 $219

Control Efficiency 26% 41% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1652 1652 1652

NOx Rate (lb/MMBtu) 0.26 0.26 0.26

NOx (TPY) 6051 6,051 6,051

Controlled Rate

NOx Rate (lb/hr) 1227 982 320

NOx Rate (lb/MMBtu) 0.19 0.15 0.05

NOx (TPY) 4495 3,596 1,170

Tons/Year Removed 1556 2,455 4,880

Total Cost/year $2,268,806 $6,818,815 $19,075,563

$/Ton $1,458 $2,777 $3,909

$/ton Incremental $5,062 $5,054

LR 2 Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $37 $57 $247

Control Efficiency 29% 43% 82%

Uncontrolled Rate

NOx Rate (lb/hr) 1688 1688 1688

NOx Rate (lb/MMBtu) 0.27 0.27 0.27

NOx (TPY) 6293 6,293 6,293

Controlled Rate

NOx Rate (lb/hr) 1199 959 312

NOx Rate (lb/MMBtu) 0.19 0.15 0.05

NOx (TPY) 4470 3,576 1,164

Tons/Year Removed 1823 2,717 5,129

Total Cost/year $2,268,806 $6,817,107 $20,941,828

$/Ton $1,244 $2,509 $4,083

$/ton Incremental $5,088 $5,856
www.AndoverTechnology.com 16

Table 4. Laramie River Estimated Control Costs

LR 3 Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $37 $57 $223

Control Efficiency 28% 42% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1778 1778 1778

NOx Rate (lb/MMBtu) 0.27 0.27 0.27

NOx (TPY) 6375 6,375 6,375

Controlled Rate

NOx Rate (lb/hr) 1279 1023 333

NOx Rate (lb/MMBtu) 0.19 0.15 0.05

NOx (TPY) 4586 3,669 1,194

Tons/Year Removed 1789 2,706 5,181

Total Cost/year $2,268,806 $6,890,841 $19,544,833

$/Ton $1,268 $2,546 $3,772

$/ton Incremental $5,039 $5,114
www.AndoverTechnology.com 17

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. The reported emissions levels shown in Table 2 

do not yet fully reflect the anticipated NOx reductions from 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 7. Like the other plants, SNCR costs are assumed to be $20/kW. 

If SCR were installed on units 1 and 2 it may be necessary to install an SCR reactor above the ESP and on 

the other side of the retired chimney from the boiler. In such a case, the ductwork from the economizer 

to the SCR and from the SCR to the air preheater inlet would be longer than usual for a high dust SCR 

and would need to go around the retired chimneys. 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, like Units 1 and 2,

impacts the length of ductwork that would 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). In estimating the 

cost of the SCR, I assume that the retrofit difficulty is above average, and an assumed retrofit difficulty 

factor of 1.3 is assumed. Results of cost calculations are shown in Table 5.

Figure 7. Naughton Units 1-3

–
www.AndoverTechnology.com 18

Table 5. Naughton Estimated Control Costs

N 1 Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $55 $75 $330

Control Efficiency 59% 69% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 895 895 895

NOx Rate (lb/MMBtu) 0.52 0.52 0.52

NOx (TPY) 3553 3553 3553

Controlled Rate

NOx Rate (lb/hr) 366 274 87

NOx Rate (lb/MMBtu) 0.21 0.16 0.05

NOx (TPY) 1453 1090 345

Tons/Year Removed 2100 2463 3209

Total Cost/year $932,466 $2,637,981 $7,747,105

$/Ton $444 $1,071 $2,414

$/ton Incremental $4,694 $6,854

N 2 Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $40 $60 $300

Control Efficiency 60% 70% 90%

Uncontrolled Rate

NOx Rate (lb/hr) 1174 1174 1174

NOx Rate (lb/MMBtu) 0.52 0.52 0.52

NOx (TPY) 4337 4337 4337

Controlled Rate

NOx Rate (lb/hr) 474 356 112

NOx Rate (lb/MMBtu) 0.21 0.16 0.05

NOx (TPY) 1752 1314 415

Tons/Year Removed 2586 3024 3922

Total Cost/year $883,900 $2,967,010 $9,216,804

$/Ton $342 $981 $2,350

$/ton Incremental $4,757 $6,957
www.AndoverTechnology.com 19

Table 5. Naughton Estimated Control Costs

N 3 Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $3 $23 $247

Control Efficiency 10% 37% 86%

Uncontrolled Rate

NOx Rate (lb/hr) 1266 1266 1266

NOx Rate (lb/MMBtu) 0.37 0.37 0.37

NOx (TPY) 4544 4544 4544

Controlled Rate

NOx Rate (lb/hr) 800 173

NOx Rate (lb/MMBtu) 0.33 0.23 0.05

NOx (TPY) 4101 2871 621

Tons/Year Removed 442 1673 3922

Total Cost/year $106,393 $5,180,724 $13,691,175

$/Ton $240 $3,097 $3,491

$/ton Incremental $4,124 $3,783
www.AndoverTechnology.com 20

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 8. There is 

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

to be possible. Therefore, the difficulty of this retrofit is probably average to above average since it is 

common to have some amount of relocation of equipment. A conservative estimate of retrofit difficulty 

is 1.3.

Table 6 shows the results of cost calculations.

Figure 8. Wyodak Power Plant
www.AndoverTechnology.com 21

Table 6. Wyodak Estimated Control Costs

Cost from 2003 emission levels

Combustion Control

(CC) CC and SNCR CC and SCR

Capital Cost, $/kW $36 $56 $302

Control Efficiency 27% 41% 81%

Uncontrolled Rate

NOx Rate (lb/hr) 1060 1060 1060

NOx Rate (lb/MMBtu) 0.26 0.26 0.26

NOx (TPY) 4615 4,615 4,615

Controlled Rate

NOx Rate (lb/hr) 775 620 202

NOx Rate (lb/MMBtu) 0.19 0.15 0.05

NOx (TPY) 3376 2,701 880

Tons/Year Removed 1239 1,914 3,735

Total Cost/year $1,272,427 $4,491,994 $15,083,850

$/Ton $1,027 $2,347 $4,039

$/ton Incremental $4,769 $5,818