1 

Reasonable Progress (RP) Four-Factor Analysis of Control Options 

For Montana-Dakota Utilities Company, Lewis & Clark Station, in Sidney, Montana 

U.S. EPA Region 8 Air Program 

March 20, 2012 

Executive Summary

This four-factor analysis documents the basis for determination of Reasonable Progress (RP) 

control options for control of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions at 

Montana-Dakota Utilities Company (MDU), Lewis & Clark Station, an electric utility power 

plant in Sidney, Montana. The four-factor analysis consists of the following steps: 

Step 1 – Identify All Available Technologies 

Step 2 – Eliminate Technically Infeasible Options 

Step 3 – Evaluate Control Effectiveness of Remaining Control Technology 

Step 4 – Evaluate Impacts and Document Results: 

Factor 1: Cost of compliance 

Factor 2: Time necessary for compliance 

Factor 3: Energy and non-air quality environmental impacts of compliance 

Factor 4: Remaining useful life

Step 5 – Select Reasonable Progress Controls 

This analysis is based on the following submittals from MDU: 

→ Response to Reasonable Progress Request for Information Pursuant to Section 114(a) of 

the Clean Air Act, Montana-Dakota Utilities Co., Lewis & Clark Station, March 17, 2009 

(“L&C Initial Response”) 

→ Emissions Control Analysis for Lewis & Clark Station Unit 1, Prepared for MontanaDakota Utilities Co. by Barr Consultants, February 2011, Revised June 2011 (“L&C 

Emissions Control Analysis”) 

→ Revised Emissions Control Analysis for Lewis & Clark Station, in Response to EPA 

Request of November 5, 2010, Montana-Dakota Utilities Co., June 14, 2011 (“L&C 

Revised Emissions Control Analysis”) 

→ Response to EPA Questions of January 19, 2012, Regarding Fuel Switch to Natural Gas, 

Basis for SCR Cost Calculation, and SDA Efficiency, Montana-Dakota Utilities Co., 

February 10, 2012 (“L&C Feb. 10, 2012 Response”) 

→ Response to EPA Questions of February 15, 2012, Regarding Cost of Fuel Switch to 

Natural Gas, Montana-Dakota Utilities Co., February 27, 2012 (“L&C Feb. 27, 2012 

Response”) 
2 

Lewis & Clark Station is rated at 52 megawatts gross output (48 megawatts net). The primary 

source of emissions consists of a single dry bottom, tangentially fired boiler, fueled with lignite 

coal, supplemented to a very small extent with natural gas (about 0.37% of total heat input in 

2002). Maximum boiler heat input rate is 572 MMBtu per hour (corresponding to 48 MW net 

output). The lignite coal has an average heating value of 6,658 Btu/lb, sulfur content of 0.51% 

by weight, and ash content of 9.3% by weight. The natural gas has an average heating value of 

1,200 Btu per cubic foot, and sulfur content of 0.02 grains per cubic foot. This Reasonable 

Progress analysis focuses on the boiler. 

The boiler was constructed in 1957 and commenced operation in 1958. Current particulate 

matter (PM) controls consist of a multi-cyclone dust collector, installed in 1957, with design 

control of 75-80%, as well as a flooded disc wet scrubber installed in 1975, which was designed 

for 98% PM control, with a nominal SO2 control efficiency of approximately 15%, but which

MDU says has achieved up to 60% control during certain operating conditions, mainly by the 

presence of calcium in the coal, but also by MDU’s addition of lime to the existing scrubber 

system when the coal has lower calcium and higher sulfur content. Current NOx controls consist 

of low NOx burners (LNB) and a close-coupled overfire air (CCOFA) system installed in 1996. 

Estimated level of control is 33%.1

With regard to expected life of the boiler and its emission control equipment, MDU states that 

there are currently no plans or schedule for removing the facility from service,2 and that the 

remaining useful life of Unit 1 is not expected to significantly impact estimated costs.3

MDU states that average hourly controlled emissions during 2007 were 47.1 lb/hr for PM 

(calculated from GE 2007 Particulate Matter Emissions Compliance Test Report), 227.29 lb/hr 

for NOx (calculations based on 2007 annual emissions inventory data), and 306.39 lb/hr for SO2

(calculations based on 2007 annual emissions inventory data).4

 Assuming 8760 operating hours 

per year, these figures are equivalent to 206 tons/yr for PM, 995 tons/yr for NOx, and 1342 

tons/yr for SO2. Actual emissions for 2002, listed in EPA’s National Emission Inventory, were 

83 tons/yr for PM, 796 tons/yr for NOx, and 781 tons/yr for SO2. For purposes of calculating 

control costs at Step 4 below, MDU used a “baseline” of 801.7 tons/yr for NOx and 1002.1 

tons/yr for SO2.

5

 EPA has used 802 tons/yr for NOx and 1002 tons/hr for SO2 in its analysis. 

 

As discussed in Section V.D.6.b. of EPA’s Federal Register notice on the proposed Montana 

regional haze Federal Implementation Plan, the contribution from point sources to primary 

organic aerosols, elemental carbon, and PM2.5 at Montana Class I areas is very small, and 

modeling tends to confirm that PM emissions from point sources do not have a very large 

impact. Therefore, EPA is proposing that additional controls for PM are not necessary for this 

planning period. 

 

1

 L&C Initial Response, pp. 3-6; L&C Emissions Control Analysis, p. 4. 

2

 L&C Initial Response, pp. 3-6. 

3

 L&C Emissions Control Analysis, p. 6. 

4

 L&C Initial Response, pp. 5-7. 

5

 L&C Emissions Control Analysis, pp. 14, 22. 
3 

Reasonable Progress Evaluation of SO2 Emissions

Current SO2 control consists of a flooded disc wet scrubber which was designed for 98% PM 

control, with a nominal SO2 control efficiency of approximately 15%, but which has achieved up 

to 60% control during certain operating conditions, mainly by the presence of calcium in the 

coal, but also by MDU’s addition of lime to the existing scrubber system when the coal has 

lower calcium and higher sulfur content. 

Step 1: Identify All Available Technologies 

EPA has identified the following technologies as being available for SO2 emission reductions 

beyond those achieved by the current control configuration at L&C Station: 

1. Wet Lime Scrubbing/Optimization of Existing Wet PM Scrubber 

2. Lime Spray Dry Absorber (SDA) and Baghouse 

3. Dry Sorbent Injection (DSI) and Baghouse 

4. Fuel Switch to PRB coal or to natural gas 

The following is a description of each available technology. 

Wet Lime Scrubbing/Optimization of Existing Wet PM Scrubber 

Wet lime scrubbing involves scrubbing the exhaust gas stream with slurry comprised of lime 

(CaO) in suspension. The process takes place in a wet scrubbing tower located downstream of a 

PM control device to prevent the plugging of spray nozzles and other problems caused by the 

presence of particulates in the scrubber. The SO2 in the gas stream reacts with the lime to form 

calcium sulfite (CaSO3•2H2O) and calcium sulfate (CaSO4). 

This control option is functionally equivalent to “Lime Spray Forced Oxidation” (LSFO) in 

terms of concept and control efficiency. Forced oxidation is used in wet scrubbing systems to 

convert calcium sulfite to calcium sulfate (gypsum). Air is blown through spent lime reagent to 

accomplish this reaction. This often takes place in the bottom of the wet scrubber. Calcium 

sulfite is a watery compound and cannot be de-watered. It is typically disposed in ash ponds. 

Calcium sulfate is a solid and wet scrubber blowdown can be run through a filter press for 

calcium sulfate recovery. After filtration, calcium sulfate can be disposed of as a solid waste or 

it can be sold as a raw material for drywall production. The use of forced oxidation has an 

impact on the method of scrubber waste disposal, but does not appreciably impact SO2 removal. 

This wet scrubbing option at L&C Station would involve modification to the existing PM wet 

scrubber to increase SO2 removal efficiency. The modification would primarily involve upgrade 

and optimization of the lime injection system. Expected total SO2 emissions reduction would be 

approximately 70% on an annual basis, versus the estimated 60% control currently being 

achieved (about a 10% improvement). The scrubber lime injection system would be upgraded to 

achieve this additional removal.6

 

6

 L&C Emissions Control Analysis, pp. 13-17. 
4 

Lime Spray Dryer Absorber (SDA) with Baghouse

Lime SDA is a dry scrubbing system that sprays a fine mist of lime slurry into an absorption 

tower where the SO2 is absorbed by the droplets. Once absorbed, the SO2 reacts with lime to 

form calcium sulfite (CaSO3•2H2O) and calcium sulfate (CaSO4) within the droplets. The SDA 

temperature must be hot enough to ensure that the heat from the exhaust gas causes the water to 

evaporate before the droplets reach the bottom of the tower. This leads to the formation of a dry 

powder, which is carried out with the gas and collected with a fabric filter baghouse. Spray 

dryer absorption control efficiency is typically in the 70% to 90% range, but can be as high as 

95%. EPA used 85% control for this analysis.7

To accommodate the SDA control option, the existing particulate scrubber at L&C Station would 

need to be abandoned in place and replaced with a new baghouse. This is necessary to ensure 

the required system residence time for a dry control option; otherwise, the achievable control 

efficiency would be significantly decreased. 8 

Dry Sorbent Injection (DSI) with Baghouse

DSI involves the injection of a lime or limestone powder into the exhaust gas duct work. The 

stream is then passed through a baghouse or electrostatic precipitator (ESP) to remove the 

sorbent and entrained SO2. The process was developed as a lower cost FGD option because the 

mixing occurs directly in the exhaust gas stream instead of in a separate tower. Depending on the 

residence time allowed in the system and gas duct temperature, sorbent injection control 

efficiency is typically between 50% and 70%. 

Based on the particulate loading of the existing control system, DSI is expected to achieve 

removal efficiencies of less than the design range in combination with existing controls. EPA 

used 70% for this analysis, relying on MDU’s estimate of control efficiency.9 This reflects a 

10% improvement, versus the estimated 60% control currently being achieved. 

To accommodate the DSI control option, the existing particulate scrubber at L&C Station would 

need to be abandoned in place and replaced with a new baghouse. Again, this is necessary to 

ensure the required system residence time for a dry control option; otherwise, the achievable 

control efficiency would be significantly decreased.

 10

 

Fuel Switching

Fuel switching is a control technology option. Blending of subbituminous Powder River Basin 

(PRB) coal is already employed at L&C Station, in instances where relatively poor lignite coal is 

provided to the plant. MDU’s boiler is currently permitted to blend PRB coal with the primary 

lignite fuel.11 Therefore, EPA considers a switch to PRB coal as primary fuel to be an available 

 

7

 L&C Emissions Control Analysis, pp. 13-14; L&C Feb. 10, 2012 Response, p. 3. 

8

 L&C Emissions Control Analysis, p. 15. 

9

 Id., Appendix C.1, Table C.1-4. 

10 Id., p. 15. 

11 Id., pp. 8-10. 
5 

SO2 control option, although, since there is no appreciable difference in the sulfur content 

(weight percent) of PRB coal versus lignite coal, this option might yield only marginal SO2

reductions.12

Also, since MDU has provided data indicating that natural gas is used to some extent (about 

0.37% of total heat input to the boiler in 2002, by EPA’s calculations, based on information 

supplied by MDU),13 EPA considers a fuel switch to natural gas as another available control 

option for SO2. Since pipeline quality natural gas has negligible sulfur content, EPA would 

expect a greater than 99% reduction in SO2. To supply sufficient natural gas to serve as primary 

fuel for the boiler, a new 22-mile pipeline from the nearest connection point to L&C Station 

would have to be constructed.14

Step 2: Eliminate Technically Infeasible Options

Fuel Switch to PRB Coal as Primary Fuel 

Although switching to coals with lower sulfur content and higher Btu content represents a viable 

pre-combustion method of reducing SO2 emissions, there are limitations to achievable blending. 

Switching to any fuel with an appreciably different composition and energy content would 

require boiler surface and other design changes. Previous test burns of PRB coal at the boiler 

confirm that the high flue gas temperatures, resulting from the use of PRB coal, cause significant 

fouling to boiler walls and other boiler surfaces. Due to the physical properties of PRB coal, 

coal mills and coal piping to the boiler would also need to be replaced, along with the addition of 

a railcar unloading system. A re-design of the existing boiler does not constitute a feasible 

retrofit control option. 

Further, there is no appreciable difference in the sulfur content (weight percent) of the 

subbituminous coal supplement, and reduced calcium/magnesium concentrations present in the 

subbituminous coal would also result in less inherent SO2 control. Finally, the on-site coal 

inventory is fairly limited (generally 2-3 days’ supply of lignite), due primarily to lack of 

property to safely store additional inventory.15 Therefore, a switch to PRB coal as primary fuel 

is not considered further in this evaluation. 

Step 3: Evaluate Control Effectiveness of Remaining Control Technology

A summary of emissions projections for the various control options is presented in Table 1 

below. For all options, EPA relied on the estimated control efficiencies, estimated emissions 

reductions, and emissions baseline provided by MDU.16 The emissions baseline of 1,002 tons 

per year, which is the current actual controlled SO2 emissions, was used in EPA’s analysis. 

Baseline emissions reflect average control provided by the alkaline materials present in lignite 

coal. MDU has equated the 1002.1 tpy baseline with use of the existing flooded disc wet 

 

12 Id. 

13 L&C Initial Response, p. 7. 

14 L&C Feb. 10, 2012 Response, p. 2. 

15 L&C Emissions Control Analysis, pp. 8-10. 

16 Id., p. 14. 
6 

scrubber to achieve 60% SO2 control on a continuous basis. The control efficiencies listed in the 

table below are the degree of control that is expected to be achieved on the baseline SO2

emissions. 

Table 1 

Summary of MDU Lewis & Clark SO2 Reasonable Progress Analysis 

Control Technologies

Control Technology 

Control 

Effectiveness 

(%) 

Emission 

Reduction 

(tpy) 

Remaining 

Emissions 

(tpy) 

Fuel Switch to Natural Gas 99+ 1002 negligible 

SDA with baghouse 85 1 850.3 151.8 

DSI with baghouse 10 100.2 901.9 

Existing scrubber mod. 10 100.2 901.9 

 

1

 Table C.1-3 of Appendix C.1 of the L&C Emissions Control Analysis lists a design control 

efficiency of 95% for SDA with baghouse, but page 14 of the Analysis lists an expected 

reduction of 850.3 tpy from a baseline of 1,002.1 tpy, which is equivalent to 85% reduction. 

EPA asked MDU why there are varying control efficiencies for SDA in MDU’s analysis. 

MDU replied on Feb. 10, 2012 that 95% control was assumed to be consistent with SDA 

evaluations compiled by the Federal Land Managers, and represents a screening level 

assumption. 

Step 4: Evaluate Impacts and Document Results 

Factor 1: Cost of compliance

Table 2 below provides a summary of estimated annual costs for the various control options. 

Table 2 

Summary of MDU Lewis & Clark SO2 Reasonable Progress Cost Analysis

Control 

Option

Control

Effectiveness

(%)

Tons SO2 

Reduced

from 

Baseline

Capital 

Cost ($)

Annual Cost

of Capital ($) 

(CRF=.0944)

Annual

O&M

Cost ($)

Total

Annual

Cost ($)

Average Cost

 Effectiveness

($/ton reduced)

Fuel 

switch to 

nat. gas 

99+ 1002 18,000,000 1,699,200 20,219,894 21,919,094 21,875 

SDA with 

baghouse 

85 850.3 65,979,566 6,228,004 3,827,052 10,055,056 11,825 

DSI with 

baghouse 

10 100.2 15,389,568 1,452,775 1,387,959 2,840,734 28,350 

Existing 

scrubber 

mod. 

10 100.2 270,000 25,488 113,149 138,637 1,383 
7 

EPA has relied on costs provided by MDU for these control options. For calculating the annual 

cost of capital, a 7% interest rate and 20-year equipment life were used by MDU, yielding a 

Capital Recovery Factor of 0.0944, same as specified in the Office of Management and Budget’s 

Circular A-4, Regulatory Analysis, available at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

The high annual cost of a fuel switch is due partly to the need to construct a new 22-mile natural 

gas pipeline, and partly to the large difference in cost of natural gas versus lignite coal. Natural 

gas would cost about five times as much as lignite coal to fuel the boiler.17

The costs for SDA and DSI include installation of a new baghouse, to replace the existing 

particulate scrubber, which would be abandoned in place. The need for a new baghouse was 

explained earlier in this report. 

The “Annual O&M Cost” consists of all direct and indirect costs listed by MDU in its detailed 

cost analyses, with the exception of capital cost recovery (annual cost of capital). 

Factor 2: Time necessary for compliance

For the option involving a fuel switch to natural gas as primary fuel, EPA estimates that several 

years would be needed to secure the necessary rights-of-way and install a new 22-mile pipeline 

that MDU has stated would be needed to provide a sufficient supply of natural gas.18 For the 

SDA-with-baghouse and DSI-with-baghouse control options, EPA relied on an estimate from the 

Institute of Clean Air Companies (ICAC) that approximately 30 months is required to design, 

build and install SO2 scrubbing technology.19 For the option involving modification to the 

existing scrubbing system, EPA relied on MDU’s estimate of 6 to 12 months to conduct an 

optimization study to evaluate scrubber capabilities and identify operational constraints.20

 

Factor 3: Energy and other non-air quality environmental impacts

A fuel switch to natural gas as primary fuel could significantly increase the demand for natural 

gas in the region and could increase natural gas prices for other consumers of natural gas in the 

region, as well as create impacts associated with more production of natural gas in the region. 

For the SDA-with-baghouse control option, as well as for the DSI-with-baghouse control option, 

energy impacts would include a blower requiring increased energy use and an associated indirect 

CO2 emissions increase. For the option of modifying the existing wet scrubber system, no 

appreciable energy impacts are expected. There is, however, a potential for additional water 

consumption and wastewater generation.21

 

17 L&C Feb. 27, 2012 Response lists the annual cost of lignite coal at $5,754,232, versus $25,974,126 for natural 

gas. The cost differential is $20,219,894. The capital cost for a new 22-mile pipeline is estimated at $18,000,000. 

18 L&C Feb. 10, 2012 Response, p. 2. 

19 Report from Bradley Nelson, EC/R Inc., to Laurel Dygowski of EPA, Four-factor Analysis of Control Options for 

MDU L&C Station, July 3, 2009, p. 5. 

20 L&C Emissions Control Analysis, p. 17. 

21 L&C Emissions Control Analysis, p. 16. 
8 

Factor 4: Remaining Useful Life

EPA has determined that the default 20-year amortization period is most appropriate to use as the 

remaining useful life of the facility. Without commitments for an early shutdown, EPA cannot 

consider a shorter amortization period in its analysis. 

As mentioned earlier in this report, MDU has no plans or schedule for removing the facility from 

service,22 and MDU has stated that the remaining useful life of Unit 1 is not expected to 

significantly impact estimated costs.23

Step 5: Select Reasonable Progress Controls 

EPA has considered the following four factors: the cost of compliance; the time necessary for 

compliance; the energy and non-air quality environmental impacts of compliance; and the 

remaining useful life of the source. The costs per ton of pollutant reduced are excessive for the 

three most expensive options. EPA is also taking into account the size of the facility, the baseline 

Q/D of the facility, and the potential reduction in Q/D from the controls. Based on costs of 

compliance, the small size of MDU L&C, and the relatively small baseline Q/D, EPA proposes 

to eliminate the more expensive control options (fuel switch to natural gas, SDA with baghouse, 

and DSI with baghouse). The most cost-effective control option (existing scrubber modification) 

would reduce SO2 emissions by 100 tpy, which equates to a 5.5% reduction in overall emissions 

of SO2 + NOx for this facility, or a reduction of Q/D from 29 to 27. Based on the costs of 

compliance, the relatively small size of MDU L&C, the baseline Q/D, and the modest reduction 

in Q/D, EPA finds it reasonable to eliminate this option. EPA therefore proposes to not require 

additional SO2 controls for this planning period.24

Reasonable Progress Evaluation of NOx Emissions

Current NOx controls consist of LNBs and a CCOFA system, with estimated control efficiency 

of 33%.

Step 1: Identify All Available Technologies 

EPA has identified the following technologies as being available for NOx emission reductions 

beyond those achieved by the current control configuration at L&C Station: 

1. Fuel Switch to PRB coal or to natural gas 

2. Selective Catalytic Reduction (SCR) with Separated Overfire Air and New Low-NOx

Burners (SOFA/LNB) 

 

22 L&C Initial Response, pp. 3-6. 

23 L&C Emissions Control Analysis, p. 6. 

24 As explained in Section V.D.6.b of EPA’s Federal Register notice on the proposed Montana regional haze Federal 

Implementation Plan, Q/D means the quantity of a source’s combined SO2 and NOx emissions, in tons per year, 

divided by the distance in kilometers from the source to the nearest Federal Class I area. 
9 

3. Selective Non-Catalytic Reduction (SNCR) with SOFA/LNB 

4. SOFA/LNB 

5. SNCR 

Fuel Switching

EPA considers fuel switching to PRB coal or to natural gas, as primary fuel for the boiler, as an 

available control for NOx, for the same reasons as described in the SO2 analysis above. With 

regard to a potential switch to PRB coal, higher heat content of coal can yield lower NOx

emissions in lb/MMBtu. The lignite coal used at L&C Station has an average heating value of 

6,435 Btu/lb.25 PRB coal typically ranges from 8,000 to 8,500 Btu/lb and therefore could be 

expected to have lower NOx emissions than lignite coal, per ton of coal fired. Similarly, natural 

gas could be expected to produce lower NOx emissions than lignite coal. EPA used a 65% 

reduction in its analysis.26

 

Selective Catalytic Reduction (SCR)

SCR is a post-combustion gas treatment technique that uses a reducing agent in the presence of a 

catalyst, to reduce NO and NO2 to molecular nitrogen, water, and oxygen. Ammonia (NH3) is 

commonly used as the reducing agent. Ammonia is vaporized and injected into the flue gas 

upstream of the catalyst bed, and combines with NOx at the catalyst surface to form an 

ammonium salt intermediate, which then decomposes to produce elemental nitrogen and water. 

The catalyst lowers the temperature and activation energy required for the chemical reaction 

between NOx and ammonia. The catalyst contains an active phase such as vanadium pentoxide 

on a carrier such as titanium dioxide. 

Typical SCR applications operate within the temperature range of 650 to 800o F. The addition of 

ammonia is typically at a stoichiometric ratio of 1:1 with NOx molecules. In the presence of the 

SCR catalyst, this ratio is optimal for NOx reduction while minimizing the amount of ammonia 

slip which can result when un-reacted ammonia is present in the system. Technical factors that 

impact the effectiveness of SCR include the catalyst reactor design and location, catalyst design, 

catalyst activity, SCR operating temperature, sulfur concentrations of the flue gas, and ammonia 

injection system design and operations. 

SCR technology is commonly described by the SCR reactor’s location within the flue gas path. 

There are three main locations for SCR systems at utility boilers: high-dust SCR (“HDSCR”), 

low-dust SCR (“LDSCR”), and tail-end SCR (“TESCR”). HDSCR is located closest to the 

boiler, and is “upstream” of all other pollution control devices (in terms of the path of flue gas 

 

25 L&C Feb. 27, 2012 Response. MDU cited typical heat content of 6.436 Btu/lb for lignite coal, based on 2009-

2011 average from FERC Form 1/EIA 923 reports. 

26 The AP-42 emission factor for natural gas is 170 lb/MMSCF. MDU’s February 27, 2012 letter to EPA states that 

annual natural gas consumption, if natural gas is used as primary fuel, would be 3,283 MMSCF. This yields 279 

tons per year of NOx emissions. Baseline NOx emissions used by MDU in its June 2011 analysis, with lignite coal as 

primary fuel, are 802 tons per year. Switching to natural gas would therefore represent a potential 65% reduction in 

NOx emissions. 
10 

from the boiler until it exits the utility station’s flue). LDSCR is located downstream of the 

particulate matter control device. TESCR is located downstream of both the particulate matter 

and SO2 control devices. Installation of LDSCR and TESCR is often not the preferred location 

due to economic reasons. The temperature of the flue gas stream is often too low in these areas 

for proper operation of SCR. Flue gas reheat is typically required, which involves using either 

plant steam or duct burners to raise the flue gas temperature to acceptable SCR operating 

temperatures. 

On some installations, regenerative SCR is installed. Regenerative SCRs have extra equipment 

and operating costs associated with reheating the flue gas downstream of the pollution control 

equipment. The heat recovery aspect of RSCR would diminish the need for reheat steam or 

supplemental fuel compared to traditional LDSCR or TESCR. Similar to TESCR and LDSCR, 

an operator must weight these extra costs compared to the benefit of exposing the SCR to a 

cleaner gas stream. Operators typically choose the HDSCR configuration when possible, to 

avoid the extra operational costs and equipment associated with flue gas reheat. EPA analyzed 

for HDSCR, following clarification from MDU about which version of SCR is appropriate.27

SCR has been demonstrated to achieve high levels of NOx reduction, in the range of 80% to 90% 

(or higher) control, for a wide range of industrial combustion sources, including PC, cyclone, and 

stoker coal-fired boilers and natural gas-fired boilers and turbines. For its SCR analysis, EPA 

included SOFA and LNB upstream of the SCR controls, on the basis that these controls are much 

less expensive than SCR and would enable the SCR system to use less reagent. EPA’s 

calculations reveal that a control system consisting of SCR + SOFA/LNB would be more costeffective than SCR alone, and would also achieve a higher level of control than SCR alone. EPA 

has used 87.5% control as its estimate for the combined SCR + SOFA/LNB system.28

Selective Non-Catalytic Reduction (SNCR)

SNCR involves the non-catalytic decomposition of NOx to nitrogen and water. An NOx reducing 

agent, typically ammonia or urea, is injected into the upper reaches of the furnace, through 

injection nozzles at the cyclone inlets. SNCR requires much higher reagent use than SCR 

because it does not rely on a catalyst. Reagent is typically added at a stoichiometric ratio from 

between 1.5:1 and 2:1 to achieve desired control while also minimizing ammonia slip. 

Because catalyst is not used to drive the reaction, temperatures of 1600 to 2100o

F are required. 

Typical NOx control efficiencies for SNCR range from 40% to 60%. NOx removal efficiency 

varies depending on inlet NOx concentrations, fluctuating flue gas temperatures, residence time, 

amount and type of nitrogenous reducing agent, mixing effectiveness, acceptable levels of 

ammonia slip, and presence of interfering chemical substances in the gas stream. Vendorguaranteed NOx reduction rates are in the 50% range to limit ammonia slip to 10 ppm. EPA used 

38% for SNCR alone, and 50% for the control option of SNCR with SOFA/LNB. 

 

27 L&C Feb. 10, 2012 Response, p. 2. MDU clarified that it believes the costs presented for L&C Station are most 

representative of a high-dust SCR system. 

28 MDU NOx control cost analysis by US EPA Region 8 for SCR, SOFA/LNB, and SCR + SOFA/LNB, Summary 

Spreadsheet, March 7, 2012. 
11 

L&C Station is a member of Midwest Independent Transmission System Operator (MISO) and, 

as such, is operated as called upon, based on energy demand and price. Generally, combustion 

systems on boilers are not optimized for low load operation, including associated NOx emissions. 

This is important because the efficiency of many air emission controls cannot be guaranteed at 

low load operating conditions. This is especially true for SNCR. Therefore, to reflect actual 

emission reductions on cost per ton basis, an SNCR scenario at low load operation is also 

presented in EPA’s analysis, using a 23 MW capacity as the low load operational case. Based on 

a preliminary SNCR engineering assessment that includes the temperature, residence time, and 

the current level of NOx control, an emissions reduction of approximately 15% to 30% would be 

expected at low load conditions. Relying on estimates from MDU, EPA used 16% for its 

analysis.29

Separated Overfire Air (SOFA)

SOFA diverts a portion of the total combustion air from the burners and injects it through 

separate air ports above the top level of the burners. SOFA is the typical NOx control technology 

used in coal-fired boilers and is primarily geared to reduce thermal NOx. Staging of the 

combustion air creates an initial fuel-rich combustion zone for cooler combustion. This reduces 

the production of thermal NOx by lowering combustion temperature and limiting the availability 

of oxygen in the combustion zone where NOx is most likely to be formed. SOFA technology is 

compatible with the existing LNB and would replace the existing CCOFA system 

Low NOx Burners (LNB)

LNB technology utilizes advanced burner design to reduce NOx formation through the restriction 

of oxygen, flame temperature, and/or residence time. LNB is a staged combustion process that is 

designed to split fuel combustion into two zones. In the primary zone, NOx formation is limited 

by either one of two methods. Under staged air rich (high fuel) condition, low oxygen levels 

limit flame temperatures, resulting in less NOx formation. The primary zone is then followed by 

a secondary zone in which the incomplete combustion products formed in the primary zone act 

as reducing agents. Alternatively, under staged fuel lean (low fuel) conditions, excess air will 

reduce flame temperature to reduce NOx formation. In the secondary zone, combustion products 

formed in the primary zone act to lower the local oxygen concentration, resulting in a decrease in 

NOx formation. Low NOx burners typically achieve NOx emission reductions of 25% to 50% as 

compared to uncontrolled emissions. 

LNB are currently used at L&C Station. Based on the currently achieved emission rates, a 

combined reduction in the range of 30% to 40% would be expected with the addition of SOFA 

and new LNB. Relying on estimates from MDU, EPA used 38% for its analysis.30 

Step 2: Eliminate Technically Infeasible Options

EPA considers fuel switching to PRB coal to be technically infeasible, for reasons already 

described in the SO2 analysis above. 

 

29 L&C Emissions Control Analysis, pp. 21-22. 

30 Id., pp. 19, 22. 
12 

Step 3: Evaluate Control Effectiveness of Remaining Control Technology

A summary of emissions projections for the various control options is provided in Table 3 below. 

EPA relied on information from MDU for estimated control efficiencies, expected emission 

reductions, and baseline emissions, with the exception of the control option consisting of 

HDSCR + SOFA/LNB, for which EPA performed its own analysis.31

The control efficiencies listed in the table below, other than for the SNCR low-load scenario, are 

the degree of reduction that is expected to be achieved on actual controlled baseline NOx

emissions of 802 tons per year. Similarly, the emission reductions in tons per year in the table 

are reductions from baseline emissions. For the SNCR low-load scenario, the baseline 

emissions, control efficiency and emissions reduction are those that correspond to low-load 

boiler operation (23 MW). 

Table 3 

Summary of MDU Lewis & Clark NOx Reasonable Progress Analysis Control 

Technologies

Control Option 

Control 

Effectiveness 

(%) 

Emission 

Reduction 

(tpy) 

Remaining 

Emissions 

(tpy) 

HDSCR + SOFA/LNB 87.5 693 109 

Fuel switch to natural gas 65 523 279 

SNCR + SOFA/LNB 50 401 401 

SOFA/LNB 38 301 501 

SNCR 38 301 501 

SNCR (low load) 16 58 298 

Step 4: Evaluate Impacts and Document Results 

Factor 1: Cost of compliance

Table 4 below provides a summary of estimated annual costs for the various control options. 

EPA relied on MDU’s cost figures, with the exception of HDSCR + SOFA/LNB, for which EPA 

performed its own cost calculations and estimated the control efficiency, using a combination of 

EPA’s OAQPS Control Cost Manual and control cost spreadsheets from EPA’s Integrated 

Planning Model. (MDU had calculated the capital cost of SCR alone at $38,976,000, the total 

annual cost at $6,984,376, and cost effectiveness at $9,680.) 

 

31 MDU NOx control cost analysis by US EPA Region 8 for SCR, SOFA/LNB, and SCR + SOFA/LNB, Summary 

Spreadsheet, March 7, 2012. 
13 

Table 4 

Summary of MDU Lewis & Clark NOx Reasonable Progress Analysis 

Control Technologies 

Control 

Option

Control

Effectiveness 

(%)

Tons NOx

Reduced

from 

Baseline

Capital 

Cost ($)

Annual Cost

of Capital ($) 

(CRF=.0944)

Annual

O&M

Cost ($)

Total

Annual

Cost ($)

Average Cost

 Effectiveness

($/ton reduced)

HDSCR + 

SOFA/LNB 

87.5 693 22,351,427 2,109,975 1,251,990 3,361,965 4,853 

Fuel switch 

to nat.gas 

65 523 18,000,000 1,699,200 20,219,894 21,919,094 41,934 

SNCR with 

SOFA/LNB 

50 401 4,531,000 427,694 666,268 1,093,962 2,729 

SOFA/LNB 38 301 2,195,000 207,192 157,354 364,546 1,213 

SNCR 38 301 2,433,000 229,658 531,996 761,654 2,533

SNCR 

 (low load) 

16 58 2,433,000 229,658 336,015 565,673 9,817 

For annual cost of capital, EPA used 7% interest rate and 20-year equipment life, yielding a 

Capital Recovery Factor of 0.0944, as specified in the Office of Management and Budget’s 

Circular A-4, Regulatory Analysis, available at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

For each control option, the “Annual O&M Cost” consists of all direct and indirect costs, with 

the exception of capital cost recovery (annual cost of capital). 

Factor 2: Time necessary for compliance

For combustion modifications such as SOFA and/or LNB, furnace penetration would be required 

and, as such, would need to align with a major outage. The next planned outages is spring of 

2018.32 Therefore, it might not be possible to ensure that SOFA and LNB could be installed 

within the first planning period for regional haze requirements under the CAA. If HDSCR + 

SOFA/LNB is the chosen control option, the construction schedule could extend into many 

months. If SNCR is the chosen control option, installation would likely be much quicker. For 

the option involving a fuel switch to natural as primary fuel, several years might be needed to 

secure the necessary rights-of-way and install a new 22-mile pipeline that MDU has stated would 

be needed to provide a sufficient supply of natural gas.

33

 

Factor 3: Energy and other non-air quality environmental impacts

A fuel switch to natural gas as primary fuel could significantly increase the demand for natural 

gas in the region and could increase natural gas prices for other consumers of natural gas in the 

region, as well as create impacts associated with more production of natural gas in the region. 

Other control options, however, would have minimal energy impacts. 

 

32 L&C Emissions Control Analysis, p. 26. 

33 L&C Feb. 10, 2012 Response, p. 2. 
14 

Depending on HDSCR installation in relation to existing controls, ammonia slip can generally 

cause additional ammonia to be emitted to air or water. As ammonia is both a visibility 

impairing air pollutant and a wastewater regulated pollutant, air emissions and water discharges 

can be impacted. This is also a potential SNCR impact. Also, spent catalyst from SCR produces 

an increase in solid waste. Finally, for combustion modifications (SOFA and/or LNB), there is a 

potential for increased CO emissions from the boiler. During normal operation at L&C Station, 

CO levels are currently on the order of 20 ppm. Generally, CO performance guarantees are in 

the 100 ppm to 200 ppm range for LNBs.34

Factor 4: Remaining useful life

EPA has determined that the default 20-year amortization period is most appropriate to use as the 

remaining useful life of the facility. Without commitments for an early shutdown, EPA cannot 

consider a shorter amortization period in its analysis. As mentioned earlier in this report, MDU 

has no plans or schedule for removing the facility from service, and MDU has stated that the 

remaining useful life of Unit 1 is not expected to significantly impact estimated costs. 

Step 5: Select Reasonable Progress Controls 

EPA has considered the following four factors: the cost of compliance; the time necessary for 

compliance; the energy and non-air quality environmental impacts of compliance; and the 

remaining useful life of the sources. EPA is also taking into account the size of the facility, the 

baseline Q/D of the facility, and the potential reduction in Q/D from the controls. Based on costs 

of compliance, the small size of the facility, and the relatively small baseline Q/D, EPA proposes 

to eliminate the more expensive control options (fuel switching to natural gas and HDSCR + 

SOFA/LNB). For similar reasons, taking into account costs in the low load scenario, EPA 

proposes to eliminate SNCR and SNCR + SOFA/LNB. Finally, for the most cost effective 

option (SOFA/LNB), emissions reductions would be fairly small (300 tpy), which would result 

in approximately 16.6% reduction in overall emissions of SO2 + NOx for this facility, or a 

reduction of Q/D from 29 to 24. Based on the costs of compliance, the relatively small size of 

MDU L&C, and the modest reduction in Q/D, EPA finds it reasonable to eliminate this option. 

EPA therefore proposes to not require NOx controls for this planning period. 

 

34 L&C Emissions Control Analysis, pp. 19, 23, 24.