To: Laurel Dygowski (EPA-Region 8) 

From: Bradley Nelson, ECIR Incorporated 

Date: July 3, 2009 

Subject: Four-Factor Analysis of Control Options for Montana Dakota Utilities - Lewis and 

Clark Station - Sidney, Montana 

Montana Dakotas Utilities (MDU) operates a lignite-fired boiler used to generate 

electricity at the Lewis and Clark Station. The electric generating unit (EGU) is a dry bottom, 

tangential coal-fired boiler capable of burning coal or natural gas and associated equipment for 

generation of electricity. The unit has an electric generating capacity of 48 megawatts. Pollutant 

emissions from the boilers include: nitrogen oxides (NOx), sulfur dioxide (S02), and particulate 

matter less than 2.5 microns (PM2.5)' 

Table 1 summarizes the NOx, S02 and PM2.5 emissions listed in the 2002 National 

Emissions Inventory (NEI) database for the EGU boiler. The EGU boiler is equipped with a 

multi-cyclone dust collector to reduce particulate emissions, and a flooded disk wet scrubber to 

reduce emissions of S02. The flooded disk wet scrubber system also reduces particulate 

emissions from the exhaust gas stream. A low NOx firing system with close-coupled overfire air 

(CCOFA) is used to reduce emissions ofNOx. 

Table 1. Summary of Pollutant Emissions (2002 NEI)
 

MDU - Lewis & Clark Station
 

UnitID NOx (Ton/yr) S01 (Ton/yr) PM1.5 (Ton/yr) 

796 781 83
 

The facility did not provide any uncontrolled emissions data in their responses to the 

Section 114(a) letter. The facility noted that it is not possible to operate the boiler unless the 

control technology is in operation. If the control systems are shut down, the boiler automatically 

shuts down. 

Current emissions for the facility are higher than those reported in the 2002 NEI. Table 2 

compares the 2002 NEI emissions with current emissions which are based on the 2007 emission 

rates and the average hours of operation (2005-2008) provided by the facility. Table 2 also lists 

the emission reductions achieved with the current emission control technology. 
Table 2. Comparison of Emission Rates - Lewis & Clark Station 

2002NEI Current Reported 

Pollutant Emission Rate Emission Rate Emissions 

(Ton/yr) (Tons/yrt Reduction (%l 

NOx 796 916 33% 

S0 2 781 1,224 60%
 

PM 83 188 98%
 

a Current emissions calculated from the 2007 emission rate and average hours of operation (2005-2008) provided by 

the facility in the response to Section 114 letter from Abbie Kresbach, Environmental Manager, Montana-Dakota 

Utilities Co., to Laurel Dygowski, U.S.EPA - Region 8. March 17,2009. 

b Based on the information provided in the response to Section 114 letter from Abbie Kresbach, Environmental 

Manager, Montana-Dakota Utilities Co., to Laurel Dygowski, U.S.EPA - Region 8. March 17,2009. 

Additional NOx emission reductions could be achieved with the addition of a selective 

catalytic reduction (SCR) or selective non-catalytic reduction (SNCR). These would be added to 

the current NOx combustion control system. 

Additional S02 emission reductions could be achieved by adding to the existing flooded 

disk wet scrubber (which was installed in 1975); limestone with forced oxidation (LSFO) or lime 

spray drying (LSD) control technology. To evaluate these technologies, the current emission 

rates were used to evaluate control effectiveness of the control options. 

Table 3 summarizes the NOx control options that have been identified for the EGU boiler 

and the potential NOx emission reductions. The emission reductions assume that the listed NOx 

control option is used in conjunction with the low NOx firing system and CCOFA NOx 

combustion control. Table 4 summarizes the S02 control options and the S02 emission 

reductions; The emission reductions assume the co-control of the flooded disk wet scrubber 

system with the listed S02 control option. The listed control options for both NOx and S02 have 

been retrofitted on numerous coal-fired boilers and have been proven to be effective in reducing 

the targeted emissions. 

Particulate control options were not investigated, because the current multi-cyclone 

particulate control device already achieves 98% PM2.5 emission control. Potential particulate 

control options (fabric filter, electrostatic precipitator) provide comparable particulate control. 

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Table 3. Control Options - Lewis & Clark Station 

Current Estimated Emission 

Pollutant Control Emissionsa Control Reductions 

Facility Name Source Type Controlled Option (tons/yr) Efficiency (%) (tons/yr) 

Lewis & Clark Lignite coal-fired 

Station boiler equipped with SNCR 916 35 321 

multi-cyclone, NOx 

flooded disk wet SCR 85 779 

scrubber, and low NOx 

firing system wi LSD 1,224 90 1,102 

CCOFA 502 

l5FO 95 1,163 

a Current emissions calculated from the 2007 emission rate and average hours of operation (2005-2008) provided by 

supplied in the response to the Section 114 letter from Abbie Kresbach, Environmental Manager, Montana-Dakota 

Utilities Co., to Laurel Dygowski, U.S. EPA - Region 8. March 17, 2009. 

Other methods for reducing NOx and S02 emissions from coal-fired boilers include: 

using a lower sulfur coal, switching to natural gas, co-firing natural gas, and enhancing the 

perfonnance of the current control systems. Using lower sulfur coal can reduce S02 emissions 

by limiting the amount of sulfur that can oxidize to S02 during combustion. The lower sulfur 

coal costs more per ton, but may provide a cost effective option for reducing S02 emissions. 

Switching to natural gas or co-firing coal and natural gas also reduces S02 emissions, and may 

also reduce NOx emissions. This option will increase fuel costs, but may provide a cost effective 

approach to reducing visibility impairing pollutants. Enhancement of the current control systems 

may also provide a cost effective approach to reducing S02 and NOx emissions. Replacing or 

adding spray nozzles, trays, sorbent, or scrubber vessels can increase the reduction efficiency of 

the current flooded disk wet scrubber system. 

Factor 1 - Costs 

The regional haze guidance document! states that the EPA Air Pollution Control Cost 

Manual2 should be used whenever possible to estimate annual and capital costs of installing air 

pollution control systems. The EPA Air Pollution Control Cost Manual was used to estimate 

capital and annual costs for selective catalytic reduction and selective non-catalytic reduction for 

NOx control, and wet scrubbers (WS) for S02 control. The facility already uses a wet scrubber 

to control S02 emissions so the Coal Utility Environmental Cose (CUECost) program which 

I Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program, U.S. Environmental 

Protection Agency, July 1,2007. 

2 EPA Air Pollution Control Cost Manual Sixth Edition, EPA/452/B-02-001, January 2002. 

http://www.epa.govlttn/eate/dirl/e allehs.pdf 

3 Coal Utility Environmental Cost (CUECost) Model Version 1.0. h.ttp://www.epa.gov/ttn/catc/products.html 

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provides additional S02 control technology information beyond WS was used to analyze S02 

control technologies. The CUECost economic analysis workbook was developed for EPA to 

produce rough-order-of-magnitude cost estimates (± 30% accuracy) of the installed capital and 

annualized operating costs for air pollution control (APC) systems installed on coal-fired power 

plants to control sulfur dioxide, nitrogen oxides, and particulate matter. The workbook is capable 

of calculating estimates of an integrated APC system or individual component costs for various 

APC technologies currently used in the utility. The CUECost program includes S02 control 

options for limestone with forced oxidation and lime spray drying. 

Process data from the facility's Section 114 response lcttcr was used to size the control 

equipment and estimate the capital and operation and maintenance (O&M) costs. The capital 

cost includes the purchased equipment cost, the indirect installation costs (i.e., engineering, 

general facilities, contingency), project contingency costs, preproduction costs, and the cost of 

purchasing initial inventory (i.c., limestone, lime, urea, or ammonia). The O&M costs include 

operating costs, cost of maintenance, annual reagent costs, electricity costs, catalyst replacement 

costs, as well as the amortization of the equipment over 30 years at 7% interest. The annual cost 

for the listed NOx control options includes the O&M costs for the currently installed NOx 

combustion control system. The annual cost for the listed S02 control options deducts the O&M 

costs for the current S02 control. 

Table 4 presents a summary of the capital and annual costs for retrofitting each of the 

listed control options for NOx and S02. The control efficiencies that are presented in the tables 

are based on the control efficiency that is expected for each of the control options for a coal-fired 

boiler that were listed in the EPA Air Pollution Control Cost Manual or CUECost. Table 4 also 

presents the cost effectiveness for each control measure, in terms of the cost per ton of emission 

reduction, and the incremental cost effectiveness ofthe control options in comparison to the 

currently installed control technology. The emission reductions and cost effectiveness listed in 

Table 5 for NOx include options for both the current control system and for co-control using the 

listed control option and the current NOx control system. The S02 cost effectiveness estimates 

presented in Table 4 assumc the replacement of the current control systems with the listed 

control option. 

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Table 4. Estimated Costs of Control- Lewis & Clark Station (2007 Dollars) 

Estimated Incremental 

Control Estimated Estimated Cost Cost 

Pollutant Efficiency Capital Cost Annual Cost Effectiveness Effectiveness 

Facility Name controlled Control Option (%) ($) ($/yr) ($/ton) ($/ton) 

Lewis &Clark NOx Current system" 33 464,000 53,000 135 

Station 

5NCRb 35 2,205,000 415,000 1,294 

SCRb 85 8,586,000 1,563,000 2,007 2,507 

502 Current system" 60 14,780,000 328,000 280 

LSOb 90 43,728,000 6,800,000 6,173 

LSFOb 95 60,804,000 8,854,000 7,614 33,562 

"Capital and annual costs for the existing control system were provided by the facility. The annual cost includes the 

O&M cost, but does not include the amortization of the capital cost. The current system is assumed to be fully amortized. 

b The annual cost incl udes the annual O&M costs and the amortization of the capital cost for 30 years at 7% interest. 

Factor 2 - Time Necessary for Compliance 

The Institute of Clean Air Companies (ICAC) has estimated that approximately 18 

months is required to design, fabricate, and install SCR or SNCR technology for NOx control, 

and approximately 30 months to design, build, and install S02 scrubbing technology.4 Based on 

these figures, the total time required to achieve emission reductions for this EGU boiler is 

estimated to be a total of 1Yz years for NOx strategies, and 2Yz years for S02 strategies. 

Factor 3 - Energy and Non-Air Impacts 

Table 5 shows the estimated energy and non-air pollution impacts of control measures for 

this EGU boiler. The values were obtained from an EPA report listing the performance impacts 

of each of the control technology options.5

,6 In general, the combustion modification 

technologies (LNB, OFA) do not require steam, or generate solid waste or wastewater. They 

.also do not require additional fuel to operate, and, in some cases, may decrease fuel usage 

because ofthe optimized combustion of the fuel. ' 

4 Institute of Clean Air Companies (2006), Typical Installation Timelines for NOx Emissions Control Technologies 

on Industrial Sources. 

5 Khan, Sikander (2003), Methodology, Assumptions, and References: Preliminary NOx Controls Cost Estimates for 

Industrial Boilers. 

6 Khan, Sikander (2003), Methodology, Assumptions, and References: Preliminary SOz Controls Cost Estimates for 

Industrial Boilers. 

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Retrofitting of a SNCR requires energy for compressor power and steam for mixing. 

This would produce a small increase in CO2 emissions to generate electricity; however the 

technology itself does not produce additional CO2 emissions. 

Installation of SCR on an EGU boiler is not expected to increase fuel consumption. 

However, additional energy is required to operate the SCR, which will produce an increase in 

CO2emissions to generate electricity. In addition, spent catalyst would have to be changed 

periodically, producing anincrease in solid waste disposal. However, many catalyst companies 

accept the return of spent catalyst material, where they are regenerated on-site and used again. 

Retrofitting of the S02 control options increases the usage of electricity, and produces 

both a solid waste and wastewater stream. In addition, increases of CO2 emissions will occur 

due to the increased energy usage for material preparation (e.g., grinding), materials handling 

(e.g., pumpslblowers), flue gas pressure loss, and steam requirements. Power consumption is 

also affected by the reagent utilization of the control technology, which also affects the control 

efficiency of the control technology. 

Factor 4 - Remaining Equipment Life 

The Lewis & Clark facility noted that there are no current plans for removing the unit 

from service. Therefore, the remaining life of the electrical generating unit is not expected to 

affect the cost of control technologies. 

Table 5. Estimated Energy and Non-Air Environmental Impacts of Potential Control
 

Lewis & Clark Station
 

Source Type 

Lewis & Clark 

Station 

Control Option 

SNCR 

SCR 

Pollutant 

controlled 

NOx 

NOx 

Energy and non-air pollution impacts 

376 195 

14.1 80.2 

Electricity Steam Solid waste Wastewater 

requirement requirement produced produced 

(kW) (Ib/hr) (ton/hr) (gal/min) 

LSD S02 364 3.85 

LSFO S02 1,040 7,206 0.954 

Note: A blank indicates that no impact is expected. 

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