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February 7, 2013

To: Doug Grano

Fm: Jim Staudt

Re: Review of estimated BART compliance Costs for Wyoming Electricity Generating Units (EGUs)

Attachment: Microsoft Excel Workbook WY EGU BART_RP Costs_20130201.xlsx

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

Andover Technology Partners (ATP) has evaluated the cost of NOx controls for a number of power plants 

in Wyoming that are subject to EPA’s proposed rulemaking.

1

 This memo documents a similar analysis 

for Jim Bridger Units 1-4.

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

 Combustion Controls, including Low NOx Burners (LNBs) with Separated Overfire Air (SOFA)

 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 or 2012 annual emission rates. 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 models2

 US EPA Air Pollution Control Cost Manual3

 Data provided by the facilities

 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 for estimating cost is consistent with the recommendations in the manual, such as 

inclusion of taxes, insurance and administrative costs,4and the use of overnight cost5for capital cost.

 

1 Memo, J. Staudt to D. Grano, Re: Review of Estimated Compliance Costs for Wyoming Electricity Generating Units 

(EGUs) , October 23, 2012 and an updated revision February 7, 2013

2

 Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, August 2010, EPA #430R10010.

3

EPA. 2002. EPA Air Pollution Control Cost Manual (Sixth Edition). EPA/452/B-02-001

4

Integrated Planning Model ver 4.10 documentation page 8-11

5

“overnight” costs mean exclusion of Allowance for Funds Used During Construction (AFUDC)
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Combustion Controls

For combustion controls, the capital and operating cost estimates by the owners were used. These are 

in the Wyoming Department of Environmental Quality May 28, 2009 BART Analysis. These were 

adjusted to “overnight” costs by removal of AFUDC and owner’s costs using factors developed from the 

December 2007 BART Analysis by CH2MHill which included details of the capital cost components in its 

appendices. Note that the combustion controls have already been installed on the Jim Bridger units, 

with installation dates between 2005 and 2010.

SNCR

Consistent with previous work,1for SNCR, capital cost is assumed to be $20/kW. According to the 2008 

Institute of Clean Air Companies’ SNCR White Paper,6“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 7

 Conectiv – Edge Moor unit 3 and Indian River 8

 New England Power – Salem Harbor Station 9

 Montaup Electric – Somerset Unit 8 10

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

of NOx, including SNCR.

11, 12

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 vary based 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 

 

6

Institute of Clean Air Companies, “White Paper – Selective Non-Catalytic Reduction (SNCR) for Controlling NOx Emissions”, 

February 2008, p 7.

7

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

8

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.

9

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

10 Ibid

11 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

12 "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.
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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.13

Figure 1. NOx Reduction and 

Reagent Utilization versus 

reagent treatment rate in 

NSR for a Pulverized Coal 

Fired Boiler during an SNCR 

optimization program 14

(Data points plotted below 

the curves are at unoptimized 

conditions) 

SCR

Selective Catalytic NOx Reduction (SCR) capital cost is estimated using the IPM algorithms15 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 

 

13 IPM Documentation, Appendix 5-2B.

14 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.

15

 IPM Documentation, Appendix 5-2A.
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cost model, retrofit difficulties associated with an SCR may result in capital cost increases of 30 to 50% 

over the base model. 16

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.12, 17, 18 The owners estimated capital cost of 

SCR to be $166,500,000 per unit,

19 including AFUDC. On an overnight basis, that is $154,760,000 

($292/kW),20 or about 15% greater than estimated by the IPM algorithm using a retrofit factor of 1.5 

(roughly $134 million, or $253/kW). These are both in the same range and within the range of costs 

found in industry.

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 as well as the Wyoming 

recommended BART limit are shown in Table 2.

21

 For all Jim Bridger units there has been some 

significant NOx reduction since 2003 at these facilities through implementation of additional 

combustion controls.

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 BART

recommendation*

Jim Bridger 8066 BW71 4.298E+07 0.3921 0.1929 0.1800 0.26

Jim Bridger 8066 BW72 4.090E+07 0.3705 0.1853 0.1868 0.26

Jim Bridger 8066 BW73 4.217E+07 0.3725 0.1977 0.1965 0.26

Jim Bridger 8066 BW74 4.103E+07 0.3964 0.1981 0.1936 0.26

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

* 30 day rolling average

 

16 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.

17 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

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

TECHNOLOGIES”, Prepared for Utility Air Regulatory Group, January 2010

19 Subtract cost of LNB with separated OFA from cost of LNB with separated OFA and SCR on page 13 of May 28, 

2009 report by Wyoming Department of Environmental Quality on Jim Bridger Power Plant AP-6040 BART 

Application Analysis

20 Using the same percent of total SCR cost for AFUDC as shown in appendices of CH2MHill Final Report, “BART 

Analysis for Jim Bridger Unit ,”, December 2007

21 WY Regional Haze SIP, January 7, 2011, Attachment A
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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_20130201.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,22

capital cost estimates do not include AFUDC or Owner’s Costs. For combustion controls, capital and 

operating costs were based upon what was in the Wyoming proposed SIP supporting attachments, when 

available. 

For SNCR, the capital cost was assumed to be $20/kW. Reagent consumption was determined using a 

chemical utilization factor of 0.25. After combustion controls, SNCR can typically achieve NOx 

reductions of 20% to 30%.23 NOx reduction with SNCR is known to be greater at higher NOx emission 

rates than lower rates.24 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 $450/ton of 50% by weight urea solution).

25

 

 

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

23 Institute of Clean Air Companies, February 2008, p. 9

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

July 20, 1993, Figure 6

25 Email from Doug Kirk, Fuel Tech, 10/12/2012
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Jim Bridger, Units 1-4

An overhead view of Jim Bridger plant is shown in Figure 2. 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.

26

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.

27

 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, 

except possibly the middle two which will be somewhat more difficult to achieve access for equipment. 

For this reason a retrofit difficulty factor of 1.5 is assumed for the middle units and 1.25 for the units on 

either end.

Table 3 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

 

26 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.

27 Wyoming Department of Environmental Quality on Jim Bridger Power Plant AP-6040 BART Application Analysis, 

May 28, 2009
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Figure 2. Jim Bridger Power Plant
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Table 3. Jim Bridger Estimated Control Costs

JB 1 Cost from 2003 emission levels

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $211 $39 $231

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 $3,235,461 $16,425,339 $4,402,757 $17,592,636

$/Ton $256 $4,182 $5,880 $826 $2,393

$/ton Incremental $6,530 $4,182 $6,530

JB 2 Cost from 2003 emission levels

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $251 $39 $270

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 $3,193,662 $18,590,683 $4,360,958 $19,757,979

$/Ton $308 $4,214 $6,719 $959 $3,015

$/ton Incremental $7,664 $4,214 $7,664
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Table 3. Jim Bridger Estimated Control Costs

JB 3 Cost from 2003 emission levels

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $253 $39 $273

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 $3,362,773 $18,968,124 $4,530,069 $20,135,420

$/Ton $315 $4,058 $6,141 $998 $2,961

$/ton Incremental $6,905 $4,058 $6,905

JB 4 Cost from 2003 emission levels

Combustion Control

(CC) SNCR SCR CC and SNCR CC and SCR

Capital Cost, $/kW $19 $20 $213 $39 $232

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 $3,278,694 $16,545,040 $4,445,990 $17,712,336

$/Ton $281 $4,127 $5,616 $897 $2,492

$/ton Incremental $6,165 $4,127 $6,165