To: Laurel Dygowski (EPA-Region 8) From: Bradley Nelson, 

### ECIR Incorporated Date: July 3, 2009 Subject: Four-FactorAnalysis ofControl Options for 

### Montana Dakota Utilities

- Lewis and ClarkStation

- Sidney, Montana

MontanaDakotas Utilities (MDU) operates a lignite-fired boilerused to generate electricity at the Lewis and Clark Station. The electric generating unit (EGU) is a dry bottom, tangential coal-fired boiler capable ofburning coal ornatural gas and associated equipment for generation ofelectricity. The unit has anelectric generating capacity of48 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 2002National Emissions Inventory (NEI) database for the EGU boiler. The EGU boiler is equipped with a multi-cyclone dust collectorto reduce particulate emissions, and a flooded disk wet scrubber to reduce emissions ofS02. The flooded disk wet scrubber system also reduces particulate emissions from the exhaust gas stream. A lowNOx firing system with close-coupled overfire air (CCOFA) is used to reduce emissions ofNOx. 

### Table 1. 

### Summary ofPollutantEmissions (2002 NEI) MDU

- Lewis & 

### ClarkStation UnitID NO x (Ton/yr) S01 (Ton/yr) PM 1.5 

### (Ton/yr) 796 781 

### 83

The facility did not provide any uncontrolled emissions data in theirresponses to the Section 114(a) letter. The facility noted that it is not possibleto operate the boiler unless the control technology is in operation. Ifthe control systems are shut down, the boiler automatically shuts down. Current emissions for the facility are higher than thosereported 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 ofoperation (2005-2008) provided by the facility. Table 2 also lists the emission reductions achieved with the current emission control technology.

### Table 2. Comparison ofEmission Rates

- Lewis & 

### ClarkStation 

### 2002NEI Current Reported Pollutant Emission Rate Emission Rate Emissions (Ton/yr) (Tons/yrt Reduction (%l NO

### x 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 ofoperation (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 couldbe achieved with the addition ofa selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR). These would be added to the currentNOx combustion control system. Additional 

### S02emissionreductions 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 ofthe control options. Table 3 summarizes the NOx control options that have beenidentified 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 emissionreductions assume the co-control ofthe flooded disk wet scrubber system with the listed 

### S02 control option. The listed control options for bothNOx and 

### S02 have beenretrofitted on numerous coal-fired boilers and have beenproven 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.

2Table 3. Control Options - Lewis & Clark Station

Current Estimated Emission Pollutant Control Emissionsa Control Reductions Facility Name SourceType 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 Currentemissions calculatedfrom the 2007emission rate and average hours ofoperation (2005-2008) provided by supplied in the response tothe Section 114letterfrom 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 ofthe current control systems. Using lower sulfurcoal can reduce S02 emissions by limiting the amount ofsulfur that can oxidize to S02 during combustion. The lower sulfur coal costs more perton, but may provide a cost effective option for reducing S02 emissions. Switchingto 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 ofthe current control systems may also provide a cost effective approach to reducing S02 and NOx emissions. Replacing or adding spray nozzles, trays, sorbent, or scrubbervessels can increase the reduction efficiency of the current flooded disk wet scrubber system. 

### Factor 1 - Costs The regional haze guidance document! states thatthe EPA Air Pollution Control Cost Manual2should be used wheneverpossible to estimate annual and capital costs ofinstalling 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 S02control. 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 Underthe Regional Haze Program, U.S. Environmental Protection Agency, July 1,2007. 2 EPA Air Pollution Control CostManual 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 3provides 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) ofthe 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 ofcalculating estimates ofan integrated APC system or individual componentcosts for various APC technologies currently used in the utility. The CUECostprogram 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, andthe cost of purchasing initial inventory (i.c., limestone, lime, urea, or ammonia). The O&M costs include operating costs, cost ofmaintenance, annual reagent costs, electricity costs, catalystreplacement costs, as well as the amortization ofthe 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 ofthe capital and annual costs for retrofitting each ofthe listed control options for NOx and S02. The control efficiencies that are presented inthe tables are based on the control efficiencythat is expected for each ofthe control options for a coal-fired boilerthat were listed in the EPAAir Pollution Control CostManual or CUECost. Table 4 also presents the costeffectiveness for each control measure, in terms ofthe costperton ofemission reduction, and the incremental cost effectiveness ofthe control options in comparisonto the currently installed control technology. The emission reductions and cost effectiveness listed in Table 5 for NOx include options for boththe current control system and for co-control using the listed control option and the currentNOx control system. The S02 cost effectiveness estimates presented in Table 4 assumc the replacement ofthe current control systems with the listed control option.

4Table 4. Estimated Costs ofControl- 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 costsforthe existingcontrol systemwere provided by the facility. The annual cost includesthe O&M cost, but does not include the amortizationofthe capital cost. The currentsystem is assumed to be fully amortized. bThe annual cost includesthe annual O&M costs and the amortization ofthecapital costfor 30years at7% interest.



### Factor2 - Time Necessaryfor Compliance The Institute ofClean Air Companies (ICAC) has estimated that approximately 18 months is required to design, fabricate, and install SCR or SNCRtechnology 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 estimatedto be a total of 1

### Yz years for NOx strategies, and 

### 2Yz years for 

### S02 strategies.


### Factor3 - Energyand Non-Air Impacts Table 5 shows the estimated energy and non-air pollution impacts ofcontrol measures for this EGUboiler. The values were obtained from an EPA report listing the performance impacts ofeach ofthe 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 ofthe fuel. '

4 Institute ofClean 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. 5Retrofitting ofa SNCRrequires energy for compressorpower and steam for mixing. This would produce a small increase in CO2emissions to generate electricity; however the technology itselfdoes not produce additional CO2emissions. Installation ofSCR on an EGU boiler is not expectedto 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 ofspent catalyst material, where they are regenerated on-site and used again. Retrofitting ofthe S02 control options increases the usage ofelectricity, and produces both a solid waste and wastewater stream. In addition, increases ofCO2emissions 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 ofthe control technology, which also affects the control efficiency ofthe control technology.


### Factor4 - RemainingEquipmentLife The Lewis & Clark facility noted that there are no current plans for removing the unit from service. Therefore, the remaining life ofthe electrical generating unit is not expected to affect the cost ofcontrol 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.

6