Emissions Control Analysis for 

Lewis & Clark Station Unit 1

Response to November 2010 US EPA Request for 

Additional Reasonable Progress Information

Prepared for

Montana-Dakota Utilities Co. 

February 2011

Revised June 2011

4700 West 77th Street

Minneapolis, MN 55435-4803

Phone: (952) 832-2600

Fax: (952) 832-2601
i

Emissions Control Analysis for Lewis & Clark Station Unit 1

February 2011

Table of Contents

1.0 Executive Summary ............................................................................................................................... 1

2.0 Introduction ............................................................................................................................................ 3

2.1 Overview of Emissions Control Analysis Approach .................................................................. 3

2.2 Unit Description and Current Permit Limits ............................................................................... 4

3.0 Basis for Analysis of Control Options .................................................................................................... 6

3.1 Four Factor Analysis ................................................................................................................... 6

3.2 Particulate Matter Considerations ............................................................................................... 7

4.0 Long-Term Coal Variability and Impact on Control Effectiveness ....................................................... 8

4.1 Fuel Switching Considerations ................................................................................................. 10

5.0 SO2 Control Evaluation ........................................................................................................................ 12

5.1 SO2 Control Technology Descriptions ...................................................................................... 12

5.1.1 Lime Spray Dryer Absorber (SDA) with Baghouse .................................................... 13

5.1.2 Dry Sorbent Injection (DSI) with Baghouse ................................................................ 13

5.1.3 Wet Lime Scrubbing .................................................................................................... 13

5.2 Summary of Evaluated Factors ................................................................................................. 14

5.2.1 Control Cost Evaluation ............................................................................................... 14

5.2.2 Other Considerations ................................................................................................... 15

5.3 Proposed SO2 Control Strategy ................................................................................................. 16

6.0 NOx Control Evaluation ....................................................................................................................... 18

6.1 NOx Control Technology Descriptions .................................................................................... 18

6.1.1 Combustion Controls ................................................................................................... 19

Separated Overfire Air (SOFA) ................................................................................... 19

Low NOx Burners (LNB) ............................................................................................ 19

6.1.2 Post Combustion Controls ........................................................................................... 20

Selective Catalytic Reduction (SCR) ........................................................................... 20

Selective Non-Catalytic Reduction (SNCR)................................................................ 21

6.2 Summary of Evaluated Factors ................................................................................................. 22

6.2.1 Control Cost Evaluation ............................................................................................... 22

6.2.2 Other Considerations ................................................................................................... 23

6.3 Proposed NOx Control Strategy ............................................................................................... 25

7.0 Proposed Emissions Control Strategy .................................................................................................. 26
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List of Tables

Table 1. Control Effectiveness of Technically Feasible SO2 Control Options...................................14

Table 2. SO2 Control Cost Summary................................................................................................15

Table 3. SO2 Control Technology Impacts Summary .......................................................................16

Table 4. Control Effectiveness of Technically Feasible NOx Control Options..................................22

Table 5. NOx Control Cost Summary ..............................................................................................23

Table 6. NOx Control Technology Impacts Summary ......................................................................24

Table 7. Proposed Regional Haze Emission Limits..........................................................................27

List of Figures

Figure 1. Historical Coal Energy Content (Btu) ................................................................................. 9

Figure 2. Historical Coal Sulfur Content (%) ..................................................................................... 9

List of Appendices

Appendix A – November 2010 EPA 114 Request Letter 

Appendix B – L&C Station Title V Permit

Appendix C.1 – Control Cost Worksheets

Appendix C.2 – Low Load Operation NOx Control Cost Worksheets 

Appendix D – Coal Variability Data

Appendix E – General Arrangement Drawings

Appendix F – Ammonia Slip Water Impacts
1

1.0 Executive Summary

This report presents the background and methods for the analysis of a Reasonable Progress (RP) 

emissions control strategy for the Montana-Dakota Utilities Co. (Montana-Dakota) Lewis & Clark 

Station Unit 1 located in Sidney, MT (L&C Station). Unit 1 is a dry-bottom, tangentially-fired boiler 

that started operation in 1958. The boiler is currently permitted to burn lignite coal, which can be 

supplemented as needed with subbituminous coal and natural gas. L&C Station has one steam turbine 

with a capacity of up to 56 megawatts. 

Pursuant to Section 114 of the Clean Air Act, the Environmental Protection Agency (EPA) has issued 

two requests to Montana-Dakota to provide information for Unit 1 to assist with the development of a 

Regional Haze Federal implementation plan (RH FIP). In an initial Section 114 request from January 

2009, EPA requested general information about Unit 1 and its associated air emissions control 

equipment. Montana-Dakota provided responses to the initial request in February 2009. A second 

request was sent by EPA and received by Montana-Dakota in November 2010 (Appendix A). It

requests an analysis of RP control options for Unit 1. This report provides information responsive to 

EPA’s November 2010 request.

Per the EPA recommendations in the November 2010 request, the guidelines included in 40 CFR 51

Appendix Y are used to evaluate costs associated with potential emission controls at Unit 1 for the 

Regional Haze program. The existing pollution control equipment includes a multi-cyclone dust 

collector and wet scrubber for particulate matter control along with low NOx burners (LNB) and 

close-coupled overfire air (CCOFA) for NOx control. The particulate scrubber also achieves nominal 

SO2 removal. 

Based on the results of technical feasibility reviews, economic impact analyses and consideration of 

other non-air quality energy and environmental factors, Montana-Dakota proposes the following 

emission reductions for RP purposes: 

• For particulate matter (PM), the existing emission limit of 0.17 lb/MMBtu will be maintained 

using the existing multi-cyclone and scrubber systems. This limit includes both filterable and 

condensable particulate contributions. Based on evaluations completed at other utilities, 

additional/replacement PM controls would provide negligible visibility improvement and 

would require significant capital expenditures. Pending the findings of planned scrubber 

optimization studies, the impacts of the proposed SO2 control strategy may: (a) require that 
2

the existing PM emission limit include only filterable particulate contributions; or (b) require 

a permit modification to accommodate any increases in condensable particulate emissions.

• Separated Overfire Air (SOFA) and Low NOx Burners (LNB) are proposed for RP NOx 

control with a proposed emission rate of 0.25 lb/MMBtu on a 12-month rolling basis under 

normal operational conditions. The current burner system is proposed to be completely 

replaced with an upgraded SOFA/LNB system. 

• SO2 emissions will be reduced by optimizing the existing particulate scrubber and lime 

injection system to achieve a total SO2 emissions reduction of approximately 70% on an 

annual basis. The scrubber lime injection system is proposed to be upgraded to achieve 

additional removal with a proposed limit of 0.45 lb/MMBtu on a 12-month rolling basis. An 

optimization study will be conducted to more accurately determine the lb/MMBtu limit and 

to develop an understanding of operational constraints, if any, posed by continuous lime 

addition.
3

2.0 Introduction

On July 15, 2005, the U.S. Environmental Protection Agency (EPA) published the final rules for 

regional haze and best available retrofit technology (BART). The BART rules, originally 

promulgated in September 1999, were in effect as of September 6, 2005.

The rules require that each state develop a Regional-Haze State Implementation Plan (RH SIP) to 

improve visibility in federally-protected national parks and wilderness areas (Class I areas). The SIP

must require BART on all BART-subject sources and mandate a plan to achieve natural background 

visibility by 2064. Each state must submit an RH SIP that includes milestones for establishing 

reasonable progress (RP) towards the visibility improvement goals, and plans for the first five-year 

progress period. Upon submission of the SIP, the requirements for BART sources are made 

enforceable through rules, administrative orders or revisions to existing Title V operating permits. 

The State of Montana declined to address RH SIP requirements and, as such, EPA is administering 

RH implementation, including RP, as part of the Montana RH FIP. As the next phase in achieving 

RH reductions, EPA is therefore, evaluating additional controls from non-BART eligible units that 

may assist in meeting RP goals. 

2.1 Overview of Emissions Control Analysis Approach

Information provided through this RP emissions control evaluation for Unit 1 at L&C Station is 

expected to be used by EPA in the RH FIP for Montana. The evaluation is specific to Unit 1. Other 

emission units at L&C Station are not included in the analysis pursuant to the EPA request for 

information. Although L&C Station was not subject to BART, emission controls and limitations may 

be evaluated under the auspices of “reasonable progress goals” (RPGs) under the Regional Haze Rule 

(RHR) [40 CFR 51.308(d)(1)]. In contrast to the requirements for BART evaluations [40 CFR 

51.308(e)], RP evaluations focus on the analysis of the four factors set forth in 40 CFR 

51.308(d)(1)(i)(A), as described in Section 3.0 below. While the four factors do not require an 

evaluation of visibility related impacts, Section 2.0 notes that RP by definition is a measure of 

visibility improvement. L&C Station Unit 1 is a relatively small power facility and it is unclear 

whether the current facility’s emissions have an impact on visibility in Class I areas. Although a 

visibility impact evaluation is not included in this report, Montana-Dakota reserves the right to 

provide additional information regarding such impacts as it relates to the findings in this report. 

Based on summaries developed by the National Park Service (NPS) of evaluations conducted for 

other utilities and boilers that are subject to BART, Montana-Dakota was able to streamline the RP 
4

evaluation for Unit 1. Technologies that were covered in certain BART evaluations have been 

screened out due to inapplicability with Unit 1’s small size and firing style along with commercial 

availability for this application. This analysis, therefore, focuses on cost effective and realistic 

options that have been considered BART, instead of an all-inclusive review of technologies that, 

while available, would simply not fit with Unit 1. 

2.2 Unit Description and Current Permit Limits

Unit 1 is a dry-bottom, tangentially-fired boiler which began operation in 1958. Unit 1 is fired with 

lignite coal, but can be supplemented with Powder River Basin (PRB) coal and natural gas on a 

limited basis. The maximum sustainable capacity of the unit is dependent on the type of fuel fired 

and is in the range of 48 MW for lignite fuel only (normal operating scenario) and can be as high as 

56 MW when fired with natural gas only. A summary of the existing controls and permit limits for 

visibility impairing pollutants is provided below. The Title V air operating permit for L&C Station 

(OP0691-05) can be found in Appendix B.

Particulate Matter (PM): Permit limits of 0.08 gr/dscf and 0.17 lb/MMBtu

Unit 1 was constructed with a multi-cyclone dust collector for particulate control, with a design 

control efficiency of 75%-80%. A flooded-disc wet scrubber with a design control of 98% was 

installed in 1975. The permit limit includes both filterable and condensable particulate 

contributions.

Sulfur Dioxide (SO2): Permit limit of 2.0 lb SO2/MMBtu

The flooded-disc wet scrubber is designed for particulate control with a nominal SO2 control 

efficiency of approximately 15%. In practice, up to 60% SO2 control has been achieved during 

certain operating conditions, mainly by the presence of calcium in the coal, but also by adding 

lime to the existing scrubber system when the coal has lower calcium and higher sulfur content. 

Oxides of Nitrogen (NOx): Permit limit of 0.40 lb NOx/MMBtu 

NOx controls currently consist of low NOx burners (LNB) and close-coupled overfire air

(CCOFA) system installed in 1996.
5

Other Relevant Emission Controls: Mercury control limit of 1.5 lb/TBtu on a 12-month rolling 

basis 

Montana-Dakota recently installed a mercury control system at Unit 1 to comply with

requirements under the Administrative Rules of Montana (ARM 17.8.771). An oxidizing agent 

and activated carbon injection (OA/ACI) system has been installed for mercury control. The 

injection of additional particulate into the system has increased PM/PM10 loading to the scrubber 

system. With respect to RP controls, it is noted that compliance with the existing PM limits could 

be jeopardized by certain additional control options that introduce additional particulate. The 

oxidizing agent used for mercury control is calcium bromide (CaBr) which is used to treat the 

coal prior to, and during, combustion.
6

3.0 Basis for Analysis of Control Options

3.1 Four Factor Analysis

In accordance with the requirements of 40 CFR §51.308(d)(1)(i)(A) and pursuant to the EPA request 

for information dated November 5, 2010, a four factor analysis is employed to evaluate technically 

feasible emission control options at Unit 1. 

1. Costs of compliance – The costing methodology used to evaluate the capital and operating 

costs for evaluated control options is from EPA’s Control Cost Manual1

2. Time necessary for compliance –To effectuate emission reductions in the near-term, it is 

important to give consideration to the timeline necessary for implementation of proposed RP 

controls. New add-on controls or complete replacement of existing controls require 

significantly longer timeframes for implementation as compared to retrofit and optimization 

options for existing controls. Preference is therefore given to retrofit options in this step of 

the evaluation.

. In lieu of site 

specific cost evaluations, proposed BART control summaries developed by the Federal Land 

Managers (FLMs) were used to estimate certain inputs to EPA’s calculation methodology. 

Inputs from FLM data summaries were normalized to account for the size of Unit 1 and 

related economies of scale. In addition to average cost effectiveness (cost per ton of pollutant 

removed), an evaluation of incremental cost effectiveness is also considered. Incremental 

dollar per ton cost analyses are used to illustrate the economic effectiveness of one 

technology in relation to the others. In determining the economic reasonability of evaluated 

controls, Montana-Dakota has considered, and used as a guide, thresholds for justifiable costs 

presented for control technologies under other regulatory programs (i.e., Standards of 

Performance in 40 CFR 60) and cost thresholds used in other BART and RP evaluations

(including Montana-Dakota’s R.M. Heskett Station). 

3. Energy and non-air quality environmental impacts of compliance – Impacts related to 

water quality, criteria pollutants not considered to be visibility impairing, energy impacts and 

other environmental issues raised by the proposed control technologies are included as part of 

the RP evaluation.

4. Remaining useful life of the source –The remaining useful life of the source is considered 

as part of the overall cost. The methods for calculating annualized cost of control 

technologies are included in EPA’s Control Cost Manual, which incorporates assumptions 

related to the remaining useful life of the source. No additional discussion of this factor is 

included in the RP evaluation as the remaining useful life of Unit 1 is not expected to

significantly impact estimated costs.

 

1 EPA Air Pollution Control Cost Manual – Sixth Edition. US EPA Office of Air Quality Planning and Standards 

(EPA/452/B-02-001), January 2002.
7

The determination of technical feasibility for the evaluated controls is based on physical, chemical 

and engineering principles. To be considered technically feasible, a control must have been 

previously installed and operated successfully on a similar source under similar physical and 

operating conditions. Novel controls that have not been demonstrated on full-scale, coal-fired utilities 

have not been considered. Instead, this evaluation focuses on commercially demonstrated control 

options. Consideration has also been giving to characteristics specific to Unit 1, which, by definition,

preclude the application of certain control technologies.

The degree of control for each evaluated technology is expressed on a 12-month rolling average basis 

and represents the annual tons of pollutant removed to account for expected variability in emissions 

and provide a comparable basis for each of the control options. 

3.2 Particulate Matter Considerations

The intent of RP goals is to reduce visibility impacts in Class I areas. As such, this RP evaluation 

focuses on SO2 and NOx, which are the two key regulated pollutants known to contribute to visibility 

impairment at Class I areas. By comparison, PM accounts for a relatively small amount of visibility 

impairment. Additionally, the existing PM controls and permit conditions provide effective emissions 

reductions. As such, augmenting or adjusting existing PM controls will not provide any appreciable 

incremental visibility improvement. Based on BART evaluations of particulate controls for coal-fired 

utilities, it is evident that achieving additional levels of PM reductions requires large capital 

expenditures with negligible returns in terms of emission reductions and corresponding visibility 

improvement. 
8

4.0 Long-Term Coal Variability and Impact on 

Control Effectiveness

For the purpose of establishing representative emission rate predictions, it is important to give 

consideration to variability in coal characteristics and corresponding boiler operating performance. 

To this end, Montana-Dakota provides a summary of past coal analyses for consideration in the RP 

evaluation. The analyzed data set includes 567 weekly readings covering the time period from 

January 2000 through November 2010, which illustrates the variability between shorter-term vs. 

annual achievable limits. 

L&C Station’s lignite coal is supplied by the Savage Mine. Because L&C Station is essentially the 

primary consumer for the Savage Mine, a range of coal qualities must be accepted. As illustrated by 

the variability in energy represented in British thermal units (Btu) and in sulfur content in Error! 

Reference source not found. and Figure 2 respectively, significant changes in quality occur on both 

a short and long term basis. Figures 1 and 2 show weekly sampling data presented as analyzed at 

L&C Station. Monthly and annual block average data are also summarized. Additional data on coal 

characteristics are presented in Appendix D. In order to include at least 98% of expected scenarios

and appropriately determine a consistently achievable emission limit, a high level of fuel variability 

must be assessed. This provides a degree of comfort with the operational limit and expected 

variability determined from past operational data. 
9

5900

6100

6300

6500

6700

6900

7100

7300

7500

Dec 1999 Apr 2001 Sep 2002 Jan 2004 May 2005 Oct 2006 Feb 2008 Jul 2009 Nov 2010

Average Energy Content (btu)

Year

Weekly

Monthly

Annual

Figure 1. Historical Coal Energy Content (Btu)

0.20

0.40

0.60

0.80

1.00

1.20

1.40

Dec 1999 Apr 2001 Sep 2002 Jan 2004 May 2005 Oct 2006 Feb 2008 Jul 2009 Nov 2010

Average Sulfur Content (%)

Year

Weekly

Monthly

Annual

Figure 2. Historical Coal Sulfur Content (%)
10

Savage Mine is currently in negotiations to obtain rights to mine additional sections of the existing 

coal deposit. Therefore, a mine plan with core samples to predict future coal quality is not available. 

Mine plans are variable in nature, and in lieu of predicted coal composition data, historical actual 

data serves as the best currently available guide for future coal quality expectations. The coal trends 

presented show a general decrease in quality2

In instances where relatively poor quality lignite coal is provided to the plant, some blending of 

subbituminous coal is employed. There is no appreciable difference in the sulfur content (weight 

percent) of the subbituminous coal supplement, and the as-fired sampling data presented include 

some blending of subbituminous and lignite coals. Reduced calcium/magnesium concentrations 

present in the subbituminous coal 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 the lack of property 

to safely store additional inventory. Since the need for blending coal is not easily predicted, and its 

on-hand supply is limited, it is not considered a viable option for emission reductions.

over time, and indicate the need to consider a poorer 

coal quality in estimating future emissions performance. Based on statistical analysis of the data 

presented in Figures 1 and 2, representative coal characteristics for the purpose of evaluating control 

options are assumed to be approximately 0.5% sulfur and 6,600 Btu/lb.

To ensure consistently achievable reductions given the variability and lack of predictability in the 

given fuel, Montana-Dakota proposes that long term (12-month rolling average) limits be given 

preference in the emissions limit determination for Unit 1. Based on the data presented above, 

caution should be used when attempting to derive short term emission rates from calculated annual 

emission reductions based on general control design values. The proposed long term averaging 

period is also consistent with other permits issued for proposed RP controls reviewed in preparation 

of this report. 

4.1 Fuel Switching Considerations

For some utilities, switching to coals with lower sulfur content and higher Btu content represents a 

viable pre-combustion method of reducing SO2 emissions. Although Unit 1 is currently permitted to 

blend PRB coal with the primary lignite fuel, there are limitations to achievable blending. In addition 

to physical limitations of the boiler, the supply and on-site storage of PRB that would be necessary 

for switching is not, respectively, readily proximate to or physically possible at L&C Station. 

 

2 In general, poor coal quality is indicated by low Btu content and calcium content and high sulfur content, ash 

content, and moisture content.
11

Based on Unit 1’s design and the limitations of the existing boiler operation, L&C Station is not a

candidate for fuel switching. 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 at 

Unit 1 confirm that the high flue gas temperatures, resulting from the use of PBR, cause significant 

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

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

unloading system. Re-design of the existing Unit 1 does not constitute a feasible retrofit control 

option and is not considered further in this evaluation.
12

5.0 SO2 Control Evaluation

Unit 1 currently controls SO2 emissions through calcium concentrations present in the incoming coal. 

In addition, lime can be added to the wet particulate scrubber to enhance SO2 removal when the coal 

has lower calcium content and higher sulfur content. Per EPA’s request3

, a list of SO2 flue gas 

desulfurization (FGD) control options considered in the RH evaluation is presented below:

• Lime Spray Dryer Absorber (SDA) and Baghouse

• Dry Sorbent Injection (DSI) and Baghouse

• Optimizations of Existing Wet PM Scrubber3

Descriptions for each of the evaluated controls along with discussion of feasibility concerns related 

to each control are presented in the following sections. Additional details regarding the evaluated 

controls are included in Appendix C.1. 

5.1 SO2 Control Technology Descriptions

The FGD systems commonly used to control SO2 emissions can be classified as either wet or dry 

systems. Both systems rely on creating turbulence in the gas stream to increase contact with the 

absorbing medium. Wet systems are commonly capable of achieving higher removal efficiencies than 

dry systems. FGD requires the use of an alkali reagent. Lime (or limestone) is the most widely used 

compound for acid gas absorption. Sodium based reagents are also available, and in some 

circumstances they provide better SO2 control, however, they are significantly more expensive.

Generally, it takes one molecule of reagent to capture one SO2 molecule; a stoichiometric ratio of 1. 

Wet FGD systems generally operate at a stoichiometric ratio of 1.1:1 (reagent: SO2 - i.e. 10% extra 

reagent). Dry FGD systems require stoichiometric ratios of 1.3:1 or higher to achieve optimal SO2

control.

Wet systems generally require more extensive networks of pumps and piping than dry systems to 

recirculate, collect, and treat the scrubbing liquid. As implied by the name, dry scrubbers require less 

water than wet systems, but also require higher temperatures to ensure that all moisture has been 

evaporated before leaving the scrubber. Based on site specific space constrains, installation of dry 

 

3 This technology is technically equivalent to “Lime Spray Forced Oxidation (LSFO)”. Evaluation of LSFO type 

controls was specifically requested in the December 9, 2010 call with Ms. Vanessa Hinkle of EPA regarding 

the scope of technology evaluations encompassed by the November 2010 request for information.
13

scrubbing technologies would require that the existing particulate scrubber be abandoned in place 

and replaced with a baghouse to accommodate design control efficiencies.

5.1.1 Lime Spray Dryer Absorber (SDA) with Baghouse

Lime spray dry absorption 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. A spray dry scrubber is a 

technically feasible control option for Unit 1.

5.1.2 Dry Sorbent Injection (DSI) with Baghouse

Dry sorbent injection 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. A DSI is a 

technically feasible control option for Unit 1. 

5.1.3 Wet Lime Scrubbing 

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 
14

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.

Modifications to the existing PM wet scrubber to increase SO2 removal efficiency is a feasible 

control option for Unit 1. It would primarily involve upgrades and optimization of the lime injection 

system.

5.2 Summary of Evaluated Factors

A summary of control effectiveness for each of the evaluated controls is presented in Table 1. The 

following sections describe considerations consistent with the four factor analysis requirements 

described in Section 3.1. 

Table 1. Control Effectiveness of Technically Feasible SO2 Control Options

Control Technology

Design 

Control 

Efficiency

Controlled 

Emissions 

(lb/MMBtu) 

Controlled 

Emissions 

(ton/year) 

Emission 

Reduction 

(ton/year)

SDA with Baghouse 95% 0.08 151.8 850.3

Existing Scrubber Mod. 70% 0.45 901.9 100.2

DSI with Baghouse 70% 0.45 901.9 100.2

Baseline Emissions NA 0.50 1,002.1 NA

Design control efficiencies are based on industry standard control assumptions in combination with 

sites specific baseline conditions and coal characteristics. Baseline emissions reflect average control 

provided by the alkaline materials present in lignite coal. Appendix C.1 contains additional 

references for each evaluated control technology.

5.2.1 Control Cost Evaluation

Table 2 includes the expected installed and operated costs associated with each technology based on 

reductions from the existing permitted emissions, the EPA cost model and available site specific 

information. The detailed cost analysis for each technology is provided in Appendix C.1. 
15

Table 2. SO2 Control Cost Summary

Control Technology

Installed 

Capital Cost 

(MM$)

Annualized 

Operating Cost 

(MM$/yr)

Pollution 

Control Cost 

($/ton)

Incremental 

Control Cost 

($/ton)

SDA with Baghouse $66.34 $10.05 $11,825 $13,220

Existing Scrubber Mod. $0.27 $0.14 $1,383 NA

DSI with Baghouse $15.75 $2.84 $28,347 NA

The incremental control costs listed in Table 2 represent the incremental value of each technology as 

compared to the technology with the next highest level of control. Both SDA and DSI technologies 

represent significant capital investments that are not justified on either an average cost per ton or 

incremental cost basis.

5.2.2 Other Considerations

For the dry scrubbing control options, the existing particulate scrubber would be abandoned in place 

and replaced with a baghouse to accommodate either SDA or DSI control. To ensure the required 

system residence time for either of the dry control options, the existing scrubber would need to be 

demolished, or the achievable control efficiencies for the dry scrubbing technologies would be 

significantly decreased. Additionally, physical space limitations at the site would require the 

demolition and relocation of the existing continuous emissions monitoring systems (CEMS) shelter 

along with demolition of the old Unit 1 stack to accommodate the baghouse installation. A general 

arrangement drafting for L&C Station is included in Appendix E to illustrate space limitation and 

existing equipment layouts. While capital expenditures for the demolition of existing equipment have 

not been included in the cost evaluation presented above, such costs would be in addition to and 

increase those costs reported. A more detailed evaluation of site constraints related to installing dry 

SO2 control options would be needed to fully determine costs and logistics. 

Both dry scrubber additives and additional lime injection may impact particulate emissions control. 

The existing particulate control system is currently being optimized as a result of adding the OA/ACI

mercury control system as described in Section 2.2. Additional optimization tests for particulate 

loading may be needed if additional lime is introduced into the scrubber for SO2 control. Increased 

lime use in the existing scrubber will also necessitate the evaluation of increased lime storage 

capacity, either through expansion or replacement of the existing storage silo. Further environmental 

considerations for the evaluated controls are presented in Table 3 below.
16

Table 3. SO2 Control Technology Impacts Summary

Control 

Option Energy Impacts Other Impacts Economic Impacts

SDA 

Baghouse

Blower requires 

increased energy 

use and associated 

indirect CO2

emissions increase.

• Requires process downtime 

and replacement power during 

installation.

• Due to space constraints, the 

existing equipment must be 

abandoned/relocated.

Economically infeasible 

on both an average 

($11,825) and 

incremental ($13,220) 

cost per ton basis.

Existing 

Scrubber 

Modification

No appreciable 

impacts. 

• Potential for particulate 

emissions increase.

• Potential for additional water 

consumption and wastewater 

generation.

• Potential for stack buildup 

related lime addition. 

Consideration for stacking 

liner materials to be included 

in scrubber optimization 

study.

Economically feasible on 

both an average ($1,383) 

cost per ton basis.

DSI

Baghouse

Blower requires 

increased energy 

use and associated 

indirect CO2

emissions increase.

• Requires process downtime 

and replacement power during 

installation.

• Due to space constraints, the 

existing equipment must be 

abandoned/relocated.

Economically infeasible 

on an average ($28,347) 

cost per ton basis. 

5.3 Proposed SO2 Control Strategy

Based on the analyses provided above, Montana-Dakota believes that modifying the existing 

scrubber represents the most reasonable control strategy. As compared to DSI and SDA technologies, 

the pollution control cost along with time for compliance is much more favorable. Additionally, 

physical facility space constraints support modifying the existing scrubber in lieu of DSI or SDA.

The installation of a continuous lime injection system is also proposed for L&C Station Unit 1. The 

SO2 control is currently achieved through the batch addition of lime to the scrubber on an as-needed 

basis to meet the current permit limit. The addition of a continuous lime injection system would lead 

to more consistent SO2 control for purposes of achieving RP reductions. Sizing a hydrated lime 

storage silo is under consideration. It would be designed and installed to alleviate current onsite lime 

storage and inventory constraints.
17

Montana-Dakota proposes to modify the existing scrubber’s lime injection system to achieve 

emission reductions at L&C Station Unit 1. It is anticipated that the SO2 emissions will thereby be 

reduced by 100.2 tpy from baseline. Also, a project is currently underway to optimize the PM 

removal of the scrubber through improved overspray. The increased fluid contact in the scrubber may 

also lead to additional SO2 reductions. 

Based on the above, a limit of 0.45 lb/MMBtu is proposed on a 12-month rolling average. MontanaDakota will use its existing CEMS to demonstrate compliance with the proposed RP limits. MontanaDakota proposes to conduct an optimization study to determine a sustainable SO2 removal efficiency

through the enhancement of the wet scrubber. The study will take into account technical, operational 

and reliability concerns, as well as other pollutant emission increases, environmental impacts and 

cost effectiveness. 

For the purpose of the optimization study, Montana-Dakota believes that a long-term (6 to 12 

months) evaluation of scrubber capabilities is warranted to identify operational constraints. As this 

effort is an upgrade to an existing system, rebalancing operation after requiring the installation of 

new equipment is expected to pose complex considerations. Increasing lime addition can impact

scrubber performance, including the potential for pH constraints and water balance issues, which 

must be accounted for along with variability in coal quality. The optimization study will evaluate 

these parameters, and provide Montana-Dakota with information regarding the long-term ability for 

the scrubber to accommodate the proposed changes. Recognizing that EPA is working under certain 

regulatory time constraints, Montana-Dakota intends to conduct the study and implement the 

proposed emission reductions as expeditiously as possible. Montana-Dakota will work with EPA to 

determine a protocol and timeline for the optimization study as necessary. 
18

6.0 NOx Control Evaluation

There are three mechanisms by which NOx production occurs: thermal, fuel and prompt NOx. Fuel 

bound NOx is a primary concern with solid and liquid fuel combustion sources; it is formed as 

nitrogen compounds in the fuel are oxidized in the combustion process. The secondary mechanism of 

NOx production is through thermal NOx formation. This mechanism arises from the thermal 

dissociation of nitrogen and oxygen molecules in combustion air. The thermal oxidation reaction is 

as follows:

N2 + O2 → 2NO (1)

Downstream of the flame, significant amounts of NO2 can be formed when NO is mixed with air. The 

reaction is as follows:

2NO + O2 → 2NO2 (2)

Thermal oxidation is a function of the residence time, free oxygen, and peak reaction temperature. 

Prompt NOx is a form of thermal NOx which is generated at the flame boundary. It is the result of 

reactions between nitrogen and carbon radicals generated during combustion. Only minor amounts of 

NOx are emitted as prompt NOx.

NOx is currently controlled at Unit 1 with the use of low NOx burners (LNB) and a close-coupled 

overfire air (CCOFA) system. Per EPA’s request4

• Combustion Controls

, a list of NOx control options considered in this RP 

evaluation is presented below:

o Separated Overfire Air (SOFA)

o Low NOx Burners 

• Post-Combustion Controls

o Selective Catalytic Reduction (SCR)

o Selective Non- Catalytic Reduction (SNCR)

6.1 NOx Control Technology Descriptions

Descriptions for each of the evaluated controls along with discussion of feasibility concerns related 

to each control are presented in the following sections.

 

4 Evaluated controls requested in the December 9, 2010 call with Ms. Vanessa Hinkle of EPA regarding the 

scope of technology evaluations encompassed by the November 2010 request for information.
19

6.1.1 Combustion Controls

Various combustion controls exist for Unit 1 NOx reduction. However, as discussed in this section, 

the only feasible controls for Unit 1 are the addition of separated overfire air (SOFA) and new low 

NOx burners (LNB). 

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 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 a cooler fuel-rich combustion zone. 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. Replacing the existing CCOFA system with 

SOFA is a technically feasible option for further NOx reduction. With modifications to combustion 

controls, there is a potential for increased carbon monoxide (CO) emissions from Unit 1. During 

normal operation at L&C Station, CO levels are currently on the order of 20 ppm. Generally, CO 

performance guarantees in the 100 ppm to 200 ppm range for low NOx burners. Although CO is not a 

visibility impairing pollutant, an increase of as much as a 400 tpy may result, which would require a 

Prevention of Significant Deterioration (PSD) permitting effort prior to commencing construction. 

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 to control NOx emissions from Unit 1. Alone or in combination with 

additional controls, installing new LNB is a technically feasible option to further reduce emissions. 
20

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. 

6.1.2 Post Combustion Controls

For post combustion controls, NOx can be reduced to molecular nitrogen (N2) in add-on systems 

located downstream of the furnace area of the combustion process. The two main techniques in 

commercial service include the selective non-catalytic reduction (SNCR) process and the selective 

catalytic reduction (SCR) process. 

Selective Catalytic Reduction (SCR)

SCR is a post combustion NOx control technology in which ammonia (NH3) is injected into the flue 

gas stream in the presence of a catalyst. SCR control efficiency is typically 70% to 90%. NOx is 

removed through the following chemical reaction:

4NO + 4NH3 + O2 → 4N2 + 6H20 (1) 

2NO2 + 4NH3 + O2 → 3N2 + 6H20 (2) 

The catalyst bed lowers the activation energy required for NOx decomposition. The catalyst contains 

an active phase such as vanadium pentoxide on a carrier such as titanium dioxide. These are used for 

their ability to lower the activation energy required for NOx decomposition. SCR requires an 

optimum temperature range of 650-800°F. The addition of NH3 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 NH3 is 

present in the system. Depending on SCR installation in relation to existing controls, ammonia slip 

can generally cause additional NH3 to be emitted to air or water. As NH3 is both a visibility impairing 

air pollutant and a wastewater regulated pollutant, air emissions and water discharges can be 

impacted. 

Typical SCR applications require soot blowers for catalyst cleaning. Firing lignite coal results in an 

exhaust stream heavily laden with particulate matter, which can contain catalyst poisons such as 

alkali earth metals. These materials cause the ash to adhere to the catalyst surface and block reaction 

sites in the catalyst pores. The catalyst plugging observed at the lignite-fired boiler at Coyote Station5

 

5 SCR catalyst Performance in Flue Gases Derived from Subbituminous and Lignite Coals. Steven A. Benson; 

Jason D. Laumb; Charlene R. Crocker; John H. Pavlish. 7/1/2004 (Appendix F)

was caused by materials that could not be cleaned by a soot blower system. Because of Coyote’s 
21

experience and the potential for comparable catalyst surface plugging at L&C Station Unit 1, 

installation of an SCR system on Unit 1 will likely be technically infeasible. Issues with SCR on 

lignite boilers are discussed in additional detail in a 2009 study completed by the North Dakota 

Department of Health (NDDH) which supports the limited feasibility of SCR.6

Selective Non-Catalytic Reduction (SNCR)

For reference, a cost 

analysis for potential SCR installation at Unit 1 has been developed, but Montana-Dakota would like 

to note that the feasibility of installing SCR at similar sources remains limited. Additionally, physical 

space constraints at L&C Station limit the opportunity for SCR system tie-ins as illustrated by the 

plot plan in Appendix E.

In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to 

convert NO to molecular nitrogen, N2, and water. SNCR control efficiency is typically 25% to 50%. 

Without a catalyst, the reaction requires a high temperature range to obtain activation energy. The 

relevant reactions are as follows: 

NO + NH3 + 1⁄4O2 → N2 + 3/2H2O (1) 

NH3 + 1⁄4O2 → NO + 3/2H2O (2) 

At temperature ranges of 1470 to 1830°F reaction (1) dominates. Similarly, 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.

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.

Based on a preliminary SNCR engineering assessment that included the temperature, residence time 

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

expected. Based on the timeline for completing the RP evaluation, a detailed assessment could not be 

conducted; therefore the percent reductions are estimates. For L&C Station, the control expectations 

 

6 Best Available Retrofit Technology – Selective Catalytic Reduction Technical Feasibility Analysis for North 

Dakota Lignite. North Dakota Department of Health, Division of Air Quality. 7/1/2009 
22

for SNCR are at the same level as could be achieved by the addition of SOFA and new LNB. It is 

also important to note that the economic analysis does not include unplanned outages to clean the 

ammonium bisulfate from the air heaters which would impact the cost per ton values presented 

below. 

6.2 Summary of Evaluated Factors

Based on the current utilization7 and design degree of control being achieved on Unit 1, Table 4

describes the expected annual emissions from each of the remaining feasible control options. A 

complete evaluation of NOx controls at low load operation is included in Appendix C.2 

Table 4. Control Effectiveness of Technically Feasible NOx Control Options

Control Technology

Expected 

Control 

Efficiency

Controlled 

Emissions 

(lb/MMBtu)

Controlled 

Emissions 

(ton/year)

Emission 

Reduction 

(ton/year)

SCR 90% 0.04 80.2 721.5

SNCR with SOFA/LNB 50% 0.20 400.9 400.9

SOFA/LNB 38% 0.25 501.1 300.6

SNCR 38% 0.25 501.1 300.6

Current OFA/LNB 

Configuration NA 0.40 801.7 NA 

SNCR (low load8) 16% 0.31 297.7 57.6

Current OFA/LNB 

Configuration (low load) NA 0.37 355.3 NA 

Based on an SNCR designed for a low concentration of ammonia slip, the control efficiency for 

SNCR is equivalent to the addition of SOFA and new LNB (identified as SOFA/LNB in Tables 4, 5 

and 6). 

6.2.1 Control Cost Evaluation

Table 5 includes the expected installed and operated costs associated with each technology based on 

reductions from the existing permitted emissions, the EPA cost model and site specific information 

as available. The detailed cost analyses for each technology are provided in Appendix C.1 and 

Appendix C.2. 

 

7 Unit 1 load/utilization has a significant impact on burner operation and degree of control achievable on a 

lb/MMBtu basis. 

8 Low load operational case presented for SNCR reflects operation at 23 MW capacity. Control efficiency and 

emission reductions are shown in relation to the current NOx control configuration operated at 23 MW.
23

Table 5. NOx Control Cost Summary

Control Technology

Installed 

Capital Cost 

(MM$)

Annualized 

Operating Cost 

(MM$/yr)

Pollution 

Control Cost 

($/ton)

Incremental 

Control Cost 

($/ton)

SCR $38.98 $6.98 $9,680 $18,368

SNCR with SOFA/LNB $4.53 $1.09 $2,729 $7,279

SOFA/LNB $2.20 $0.36 $1,213 NA

SNCR $2.43 $0.76 $2,533 NA

SNCR (low load) $2.43 $0.56 $9,817 NA

The cost summary presented for SCR is a based on a screening level evaluation, and Montana-Dakota

reserves the right to develop a site specific estimate as necessary. Additional constraints such as an 

extended need for shutdown, rerouting of piping to allow necessary residence time, potential redesign 

of backend heat recovery and associated costs have not been included in this evaluation. 

The incremental control costs listed in Table 5 represent the incremental value of each technology as 

compared to the technology with the next highest level of control. SCR represent significant capital 

investments that are not justified on a cost per ton or incremental cost basis. Similarly, SNCR is not 

justified on an incremental cost basis as associated decreases in emissions are not significantly higher 

than those achieved by SOFA/LNB.

6.2.2 Other Considerations

Ammonia slip generated as a result of post-combustion controls (SCR and SNCR) will cause 

increased ammonia concentrations in the scrubber discharge. This in turn will lead to a higher 

concentration of ammonia in the wastewater discharge, thus the installation of post-combustion 

controls could also require the installation of wastewater treatment controls. Costs associated with 

additional wastewater controls have not been quantified as part of this evaluation. Montana-Dakota

understands that the EPA will soon be updating the effluent limits for coal-fired facilities, and limits 

may be established that will significantly impact the cost of SNCR and SCR controls. 

As listed in the Montana Department of Environmental Quality’s (MT DEQ) water quality standards, 

the ammonia standard is currently no detectable concentration, with a trigger concentration of 10 

mg/L9

 

9 Circular DEQ-7 Montana Numerical Water Quality Standards. MDEQ Planning, Prevention, and Assistance 

Division - Water Quality Standards Section. August 2010.

. As illustrated in Appendix D, an ammonia slip range of 5 ppm to 10 ppm (the standard design 
24

parameters for post-combustion systems) will result in a discharged ammonia concentration range of 

8 to 17 mg/L. Therefore, as indicated, the installation of post-combustion controls may trigger 

stringent wastewater treatment controls for ammonia and other nitrogen constituents.

Post-combustion controls also increase emission risk regarding compliance with particulate emission 

limits. Increases in condensable particulate emissions potentially associated with sulfuric acid mist 

generated by SCR would jeopardize compliance with the existing permitted particulate limit of 0.17 

lb/MMBtu. As referenced in the Title V operation permit for L&C Station Unit 1, included in 

Appendix B, this limit includes both filterable and condensable particulate contributions, and 

therefore, represents a high level of total particulate control. 

As described in the control technology summaries above, combustion modifications (SOFA/LNB) 

are likely to result in a significant increase in CO emissions. Time for compliance for these controls 

will be dependent on the issuance of permits associated with a CO increase. Combustion 

modifications generally do not require additional steam or generate solid waste or wastewater. 

The energy and non-air quality environmental impacts for the feasible NOx control options are 

described in Table 6. 

Table 6. NOx Control Technology Impacts Summary

Control 

Option Energy Impacts Other Impacts Economic Impacts

SCR Reheat potentially 

required to make 

SCR technically 

feasible will result 

in high energy use 

and associated 

costs along with 

increased CO2

emissions.

1. Spent catalyst produces an 

increase in solid waste 

2. Ammonia slip concerns, which 

contributes to water quality 

impacts.

3. Additional safety and regulatory 

concerns associated with 

ammonia storage on site.

4. Oxidant may impact mercury 

removal efficiency

Economically 

infeasible on an 

average ($9.680) and 

incremental 

($18,368) cost per 

ton basis.

SOFA/LNB Minimal energy 

impacts.

1. Increase in CO emissions. Any 

CO increase may require 

permitting actions and approval 

from MT DEQ.

Economically 

feasible on an 

average ($1,213) cost 

per ton basis.
25

SNCR

(or SNCR 

with 

SOFA/LNB)

Minimal additional 

energy impacts.

1. Ammonia slip concerns, which 

contributes to water quality 

impacts.

2. Variably operating conditions 

caused by unit swinging will 

necessitate extensive O&M 

requirements.

3. Potential increase in CO 

emissions. Any CO increase may 

require permitting actions and 

approval from MT DEQ (due to 

SOFA/LNB).

Economically 

infeasible on an 

incremental ($7,279) 

basis and marginally 

feasible on an 

average ($2,533) cost 

per ton basis.

Economically 

infeasible at low load 

operation on an 

average basis 

($9,817).

6.3 Proposed NOx Control Strategy

Based on the above analysis, Montana-Dakota proposes the addition of SOFA with new LNB for 

NOx reduction at Unit 1. 

From a top down analysis, SCR is determined to be economically infeasible and has significant 

technical and other concerns on a commercial scale for a lignite fired boiler. 

The SNCR with SOFA/LNB combined technology option is not a viable retrofit technology for 

several reasons, including: 1) cost ineffectiveness (incremental $/ton cost compared to SOFA/LNB 

control option and average $/ton at low load operation), 2) negative energy and environmental 

impacts, and 3) relatively insignificant incremental emissions improvement beyond the SOFA/LNB 

control option. 

SOFA/LNB retrofit option represents the most cost effective retrofit technology for further 

controlling NOx emissions from L&C Station Unit 1.

The proposed NOx RP emissions limit for Unit 1 is 0.25 lb/MMBtu on a 12-month rolling average. 

This limit will allow the station to maintain compliance while accommodating Unit 1 variability in 

emissions related to different load operating conditions. For example, low load conditions will 

generally show an increase in NOx emissions on a lb/MMBtu basis, but will still be consistent with 

expected actual reduction of mass emissions (tpy) on an annual basis. Montana-Dakota will use its 

existing CEMS to demonstrate compliance with the proposed RP-based limit.
26

7.0 Proposed Emissions Control Strategy

Montana-Dakota proposes the following control strategy for L&C Station Unit 1 in consideration of 

the four-factor test specified at 40 CFR 51.308(d)(1)(i)(A). Montana-Dakota acknowledges that all 

factors must be weighed in making an emissions control determination for RP goals. That stated, it is 

important to precede any control determination with the understanding that L&C Station Unit 1 is a 

non-BART unit, and is less than the presumptive unit threshold of 200 MW. As such, economies of 

scale for pollution control costs are not realized at L&C Station and any resulting emission 

reductions are expected to provide little in the way of visibility improvement in Class I areas. 

• PM – Montana-Dakota proposes to comply with its existing permit limit of 0.17 lb/MMBtu

using its existing particulate control system. This report confirms that a change in PM 

emission limits is not warranted. The PM emission limit will be reviewed and may need to be 

increased if the SO2 and NOx controls other than those recommended in this report are

required since particulate emission from other evaluated controls would increase. Pending the 

findings of planned existing wet scrubber optimization studies, the impacts of the proposed 

SO2 control strategy may: (a) require that the existing PM emission limit include only 

filterable particulate contributions; or (b) require a permit modification to accommodate any 

increases in condensable particulate emissions.

• SO2 – Optimization of the existing PM wet scrubber to further reduce SO2 emissions is 

proposed. Continuous lime injection system configuration is being developed, and upon 

installation, an optimization study will be conducted to determine sustainable SO2 control 

efficiency. 

• NOx – The addition of SOFA with new LNB will be installed for NOx control. CO increases 

and associated permitting requirements related to the shift in combustion balance will be 

evaluated. Furnace penetration is required for the installation of SOFA/LNB and as such will 

need to align with a major outage. The next planned outages are scheduled for spring of 

2012, which is too soon to accommodate this retrofit, and spring of 2018. 

If a state construction permit is required to implement the proposed emissions control strategy, then 

that permitting schedule may impact the timing of the proposed emission reductions. MontanaDakota emphasizes that the SO2 reduction estimate may need to be modified to address findings of 

the proposed optimization study. The study is intended to identify and balance operational constraints 

related to increased lime injection rates. The SO2 control optimization may potentially provide 

additional reductions and in a shorter timeframe, with less cost than the installation of NOx controls 

resulting in the same visibility improvements.
27

If a PSD permit is required as a result of CO increases from implementing the NOx emissions 

reduction controls at Unit 1, the timeline for implementation will be dependent on expeditious 

issuance of a PSD permit and any other permits required by the MT DEQ to meet any specific state 

compliance requirements. Montana-Dakota will make all good faith efforts to secure any such 

permits in the event that they are required. In the event the issuance of any required permits for the 

project is not possible, for any reason, Montana-Dakota reserves the right to reevaluate the proposed 

RP control strategy and schedule with EPA. 

Table 7. Proposed Regional Haze Emission Limits

Pollutant

Current Permit 

Limit

Proposed RH Limit 

(12-month Rolling 

Average)

Estimated Pollutant 

Reduction from 

Current Emissions

PM 0.17 lb/MMBtu 0.17 lb/MMBtu N/A

SO2 2.0 lb/MMBtu 0.45 lb/MMBtu 100.2 tpy

NOx 0.40 lb/MMBtu 0.25 lb/MMBtu 300.6 tpy
Appendix A

EPA 114 Request Letter
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

REGION 8 

Ref: 8P-AR 

1595 Wynkoop Street 

DENVER, CO 80202-1129 

Phone 800-227-8917 

http://www.epa.gov/region08 

CERTIFIED MAIL - RETURN RECEIPT REQUESTED 

Abbie Krebsbach 

Environmental Manager 

Montana-Dakota Utilities Company 

400 North Fourth Street 

Bismarck, North Dakota 58501 

Dear Ms. Krebsbach: 

RE: Request for Additional Reasonable Progress 

Information for the Montana-Dakota Utilities 

Company, Lewis and Clark Generating Station, 

Pursuant to Section 114(a) of the Clean Air Act 

(42 U.S.c. Section 7414(a)) 

As you know, on July 19,2006, the Environmental Protection Agency (EPA) received a 

letter from the Montana Depamnent of Environmental Quality (MDEQ) that stated it was 

withdrawing its efforts to adopt a state implementation plan (SIP) for regional haze under EPA's 

Regional Haze Rule (RHR). found at 40 CFR 51.308. Due to Montana's announcement that it 

would not be addressing the requirements under 40 CFR 51.308, EPA Region 8 is moving 

forward with the technical and policy work needed to implement the requirements of the RHR 

under a Federal implementation plan (FIP). See Section 110(c)(I ) of the Clean Air Act (CAA), 

42 U.S.C. §7410(c)(I). 

As part of our effort to address requirements under the RHR for reasonable progress (RP) 

goals and strategies (see 40 CFR 51.308(d)( I) and 51.308(d)(3)), we previously requested 

information regarding the Montana-Dakota Utilities Company, Lewis and Clark Generating 

Station. We have reviewed the information that you submitted dated March 17, 2009 in response 

to our January 29, 2009 CAA Section 114 information request on the emission unit at yo ur 

facility. Baseo on the emissions and current control technology information you submitted, 

emissions unit I (a tangential coal/natural gas boi ler) is a source that warrants further analysis in 

considering and developing strategies for achieving the RP goal for Montana. 

Please submit an analysis of control options for this unit postmarked within 60 days of 

the date of this letter. The analysis must address the four factors included in 

40 CFR § 51.308(d)( I )(i)(A) - the costs of compliance, the time necessary for compliance, the 
energy and non-air quality environmental impacts of compliance, and the remaining useful life of 

the potentially affected sources. We suggest that the Best Available Retrofit Technology 

(BART) Guidel ines (see 40 CFR Part 51 Appendix Y) provide additional guidance on how to 

perform the cost of compliance portion of this analysis. Your analysis must consider the full 

range ofavailable control technologies and for each technology, you must consider the full range 

of emission standards including the most stringent. 

We understand this is a complicated endeavor, and we are available to answer any 

questions that you may have on the RHR or the RP analysis. We wi ll assist you in any way we 

can and look forward to working with you. 

Pursuant to Section 114 of the Clean Air Act, 42 U.S.C. §7414, and under authority duly 

delegated to the undersigned, you are required to provide us with the information specified in this 

letter. This information will be used by EPA in developing a regional haze FIP, or in the event 

MDEQ resumes development of a regional haze SIP, in assisting MDEQ in that effort and/or 

reviewing a regional haze SIP for Montana. Furthermore, information requests pursuant to 

Section 114 of the CAA are not limited to sources that are regulated by the particular rule EPA is 

implementing. For example, Section 114(a)( I) says that EPA may gather information from "any 

person who owns or operates any emission source" or "who the Administrator believes may have 

information necessary for the purposes set forth in this subsection." 

A duly authorized officer or agent of the facility must certity as true, accurate, and 

complete the response to this information by signing the enclosed Statement of Certi fication and 

returning it with the response. Such officer or agent must have sufficient knowledge and 

authority to make such representations on behalf of Montana-Dakota Utilities Company. 

Please submit your response to: 

U.S. Environmental Protection Agency Region VIll 

1595 Wynkoop Street 

Denver. CO 80202-1129 

Attention: Vanessa Hinkle, 8P-AR 

Pursuant to Section I 14(c) of the CAA, 42 U.S.C. §7414(c), and 40 C.F.R. Part 2, 

Subpart B, Montana-Dakota Utilities Company is entitled to assert a business confidentiality 

claim covering any part of the submitted information. Attachment B specified the assel1ion and 

substantiation requirements for business confidentiality claims. Failure to assert such a claim 

makes the submitted information subject to public disclosure upon request and without further 

notice to you, pursuant to the Freedom of Information Act, 5 U.S.c. Section 552. Information 

subject to a business confidentiality claim may only be made available to the public in 

accordance with 40 C.F.R. Part 2, Subpart B. 

A knowing submittal of false information in response to this request may be actionable 

under Section I 13(c)(2) of the CAA, as well as 18 U.S.c. §§ 1001 and 1341. Failure to comply 

-2-
with the terms of this request may subject Montana-Dakota Utilities Company to enforcement 

action under Section 113 of the CAA, 42 U.S.C. §7413. 

Also enclosed with this Request for Information is a Small Business Regulatory 

Enforcement and Fairness Act (SBREFA) information sheet. 

The requirements of this letter are not subject to the Paperwork Reduction Act of 1980, 

44 U.S.c. §3501 el seq. 

We appreciate your cooperation in this matter. If you have any questions please call 

Vanessa Hinkle of my staff at 303-312-6561. 

Enclosures 

cc: John Bunyak. NPS 

Sandra Silva, USFWS 

Thomas Dzomba, USFS 

Sincerely, 

h- Stephen S. Tuber 

Assistant Regional Administrator 

Office of Partnerships and Regulatory Assistance 
Appendix B 

L&C Station Title V Permit 
December 6, 2010

Andrea L. Stomberg

Montana-Dakota Utilities Co.

400 North Fourth Street

Bismark, ND 58501

RE: Final Title V Operating Permit #OP0691-05

Dear Ms. Stromberg:

The Department of Environmental Quality has prepared the enclosed Final Operating Permit #OP0691-

05, for Montana-Dakota Utilities, Inc. Lewis and Clark Station, located in the Southwest 1⁄4 of Section 9, 

Township 22 North, Range 59 East, in Richland County, Montana. Please review the cover page of the 

attached permit for information pertaining to the action taking place on Permit #OP0691-05. 

If you have any questions, please contact Shawn Juers, the permit writer, at (406) 444-2049 or by email at 

sjuers@mt.gov.

Sincerely,

Vickie Walsh

Air Permitting Program Supervisor

Air Resources Management Bureau

(406) 444-9741

 

 Shawn Juers

 Environmental Engineer

 Air Resources Management Bureau

 (406) 444-2049

VW:SJ

Enclosure 

cc: Christopher Ajayi, US EPA Region VIII 8P-AR

Carson Coate, US EPA Region VIII, Montana Office
OP0691-05 i Decision: 11/03/10

Effective Date: 12/04/10

STATE OF MONTANA

Department of Environmental Quality

Helena, Montana 59620

AIR QUALITY OPERATING PERMIT OP0691-05

Issued to: Montana-Dakota Utilities Co.

Lewis and Clark Station

400 North Fourth Street

Bismark, ND 58501

Final Date: December 4, 2010

Expiration Date: August 24, 2014

Effective Date: December 4, 2010

Date of Decision: November 3, 2010

Request Deemed Technically Complete: June 21, 2010 and August 31, 2010

Request Deemed Administratively Complete: June 21, 2010 and August 31, 2010

Administrative Amendment Request Received: May 24, 2010 and August 31, 2010

AFS Number: 030-053-0002A

Permit Issuance and Appeal Processes: In accordance with Montana Code Annotated (MCA) Sections 

75-2-217 and 218 and the Administrative Rules of Montana (ARM), ARM Title 17, Chapter 8, 

Subchapter 12, Operating Permit Program, this operating permit is hereby issued by the Department of 

Environmental Quality (Department) as effective and final on December 4, 2010. This cover sheet must 

be attached to the Date of Decision issued on November 3, 2010, and the permit must be kept on-site at 

the above named facility.
OP0691-05 ii Decision: 11/03/10

Effective Date: 12/04/10

Montana Air Quality Operating Permit

Department of Environmental Quality

SECTION I. GENERAL INFORMATION ........................................................................................1

SECTION II. SUMMARY OF EMISSION UNITS.............................................................................2

SECTION III. PERMIT CONDITIONS............................................................................................3

A. FACILITY-WIDE........................................................................................................................... 3

B. EU01: TANGENTIAL COAL-FIRED BOILER (COAL AND NATURAL GAS) .................................... 6

C. EU06: FUEL (GASOLINE) STORAGE TANK ................................................................................ 10

D. EU07: COAL STORAGE PILES ................................................................................................... 10

E. EU08: FUGITIVE COAL, ASH, AND LIME HANDLING................................................................ 12

SECTION IV. NON-APPLICABLE REQUIREMENTS...............................................................14

A. FACILITY-WIDE......................................................................................................................... 14

B. EMISSION UNITS........................................................................................................................ 15

SECTION V. GENERAL PERMIT CONDITIONS .........................................................................16

A. COMPLIANCE REQUIREMENTS................................................................................................... 16

B. CERTIFICATION REQUIREMENTS ............................................................................................... 16

C. PERMIT SHIELD ......................................................................................................................... 17

D. MONITORING, RECORDKEEPING, AND REPORTING REQUIREMENTS ......................................... 18

E. PROMPT DEVIATION REPORTING............................................................................................... 19

F. EMERGENCY PROVISIONS.......................................................................................................... 19

G. INSPECTION AND ENTRY ........................................................................................................... 20

H. FEE PAYMENT ........................................................................................................................... 20

I. MINOR PERMIT MODIFICATIONS ............................................................................................... 21

J. CHANGES NOT REQUIRING PERMIT REVISION .......................................................................... 21

K. SIGNIFICANT PERMIT MODIFICATIONS...................................................................................... 22

L. REOPENING FOR CAUSE............................................................................................................. 22

M. PERMIT EXPIRATION AND RENEWAL......................................................................................... 23

N. SEVERABILITY CLAUSE ............................................................................................................. 23

O. TRANSFER OR ASSIGNMENT OF OWNERSHIP ............................................................................. 24

P. EMISSIONS TRADING, MARKETABLE PERMITS, ECONOMIC INCENTIVES .................................. 24

Q. NO PROPERTY RIGHTS CONVEYED ........................................................................................... 24

R. TESTING REQUIREMENTS .......................................................................................................... 24

S. SOURCE TESTING PROTOCOL .................................................................................................... 24

T. MALFUNCTIONS ........................................................................................................................ 24

U. CIRCUMVENTION....................................................................................................................... 24

V. MOTOR VEHICLES ..................................................................................................................... 24

W. ANNUAL EMISSIONS INVENTORY .............................................................................................. 25

X. OPEN BURNING ......................................................................................................................... 25

Y. MONTANA AIR QUALITY PERMITS............................................................................................ 25

Z. NATIONAL EMISSION STANDARD FOR ASBESTOS ..................................................................... 26

AA. ASBESTOS.................................................................................................................................. 26

BB. STRATOSPHERIC OZONE PROTECTION – SERVICING OF MOTOR VEHICLE AIR CONDITIONERS 26

CC. STRATOSPHERIC OZONE PROTECTION – RECYCLING AND EMISSION REDUCTIONS .................. 26

DD. EMERGENCY EPISODE PLAN...................................................................................................... 27

EE. DEFINITIONS.............................................................................................................................. 27

APPENDIX A INSIGNIFICANT EMISSION UNITS .................................................................A-1

APPENDIX B DEFINITIONS AND ABBREVIATIONS ............................................................B-1
OP0691-05 iii Decision: 11/03/10

Effective Date: 12/04/10

APPENDIX C NOTIFICATION ADDRESSES............................................................................C-1

APPENDIX D AIR QUALITY INSPECTOR INFORMATION.................................................D-1

APPENDIX E PREDICTIVE OPACITY ......................................................................................E-1

APPENDIX F SO2 CEMS ............................................................................................................... F-1

APPENDIX G NOX CEMS ..............................................................................................................G-1

APPENDIX H ACID RAIN .............................................................................................................H-1

APPENDIX I COMPLIANCE ASSURANCE MONITORING (CAM) PLAN.............................I-1

APPENDIX J MEMS...........................................................................................................................J-1
OP0691-05 1 Decision: 11/03/10

Effective Date: 12/04/10

Terms not otherwise defined in this permit or in the Definitions and Abbreviations Appendix of this 

permit have the meaning assigned to them in the referenced regulations.

SECTION I. GENERAL INFORMATION

The following general information is provided pursuant to ARM 17.8.1210(1).

Company Name: Montana Dakota Utilities Co., Lewis & Clark Station

Mailing Address: 400 North Fourth Street

City: Bismarck State: North Dakota Zip: 58501 

Plant Location: Southwest 1⁄4, Section 9, Township 22 North, Range 59 East, Richland County, Montana

Responsible Official: Andrea Stomberg Phone: (701) 222-7752

Facility Contact Person: Abbie Kresbach Phone: (701) 222-7844 

Primary SIC Code: 4911

Nature of Business: Electric Services

Description of Process: MDU operates a tangential coal-fired boiler capable of burning coal or natural 

gas and associated equipment for generation of electricity.
OP0691-05 2 Decision: 11/03/10

Effective Date: 12/04/10

SECTION II. SUMMARY OF EMISSION UNITS

The emission units regulated by this permit are the following (ARM 17.8.1211):

Emissions 

Unit ID

Description Pollution Control Device/Practice

EU01 Tangential Coal and Natural Gas Fired Boiler Multi-Cyclone and Flooded Disc Wet Scrubber

EU06 Fuel (gasoline) Storage Tank None

EU07 Coal Storage Piles None

EU08 Fugitive Coal, Ash, and Lime Handling None
OP0691-05 3 Decision: 11/03/10

Effective Date: 12/04/10

SECTION III. PERMIT CONDITIONS

The following requirements and conditions are applicable to the facility or to specific emissions units 

located at the facility (ARM 17.8.1211, 1212, and 1213).

A. Facility-Wide

Conditions Rule Citation Rule Description Pollutant/Parameter Limit

A.1 ARM 17.8.105 Testing Requirements Testing Requirements -------

A.2 ARM 17.8.304(1) Visible Air Contaminants Opacity 40%

A.3 ARM 17.8.304(2) Visible Air Contaminants Opacity 20%

A.4 ARM 17.8.308(1) Particulate Matter, Airborne Fugitive Opacity 20%

A.5 ARM 17.8.308(2) Particulate Matter, Airborne Reasonable Precautions -------

A.6 ARM 17.8.308 Particulate Matter, Airborne Reasonable Precaution, 

Construction

20%

A.7 ARM 17.8.309 Particulate Matter, Fuel Burning 

Equipment

Particulate Matter E= 0.882 * H-0.1664 Or

E= 1.026 * H-0.233

A.8 ARM 17.8.310 Particulate Matter, Industrial 

Processes

Particulate Matter E= 4.10 * P0.67 or

E= 55 * P0.11- 40

A.9 ARM 17.8.322(4) Sulfur Oxide Emissions, Sulfur in 

Fuel

Sulfur in Fuel (liquid or 

solid fuels)

1 lb/MMBtu fired

A.10 ARM 17.8.322(5) Sulfur Oxide Emissions, Sulfur in 

Fuel

Sulfur in Fuel (gaseous) 50 gr/100 CF

A.11 ARM 17.8.324(3) Hydrocarbon Emissions, 

Petroleum Products

Gasoline Storage Tanks -------

A.12 ARM 17.8.324 Hydrocarbon Emissions, 

Petroleum Products

65,000 Gallon Capacity -------

A.13 ARM 17.8.324 Hydrocarbon Emissions, 

Petroleum Products

Oil-effluent Water 

Separator

-------

A.14 ARM 17.8.342 NESHAPs General Provisions SSM Plans Submittal

A.15 ARM 17.8.1212 Reporting Requirements Prompt Deviation 

Reporting

-------

A.16 ARM 17.8.1212 Reporting Requirements Compliance Monitoring -------

A.17 ARM 17.8.1207 Reporting Requirements Annual Certification -------

Conditions

A.1. Pursuant to ARM 17.8.105, any person or persons responsible for the emission of any air 

contaminant into the outdoor atmosphere shall, upon written request of the Department, provide 

the facilities and necessary equipment (including instruments and sensing devices) and shall 

conduct tests, emission or ambient, for such periods of time as may be necessary using methods 

approved by the Department.

Compliance demonstration frequencies that list “as required by the Department” refer to ARM 

17.8.105. In addition, for such sources, compliance with limits and conditions listing “as required 

by the Department” as the frequency, is verified annually using emission factors and engineering 

calculations by the Department’s compliance inspectors during the annual emission inventory 

review; in the case of Method 9 tests, compliance is monitored during the regular inspection by the 

compliance inspector.

A.2. Pursuant to ARM 17.8.304(1), MDU shall not cause or authorize emissions to be discharged into 

the outdoor atmosphere from any source installed on or before November 23, 1968, that exhibit an 

opacity of 40% or greater averaged over 6 consecutive minutes, unless otherwise specified by rule 

or in this permit.
OP0691-05 4 Decision: 11/03/10

Effective Date: 12/04/10

A.3. Pursuant to ARM 17.8.304(2), MDU shall not cause or authorize emissions to be discharged into 

the outdoor atmosphere from any source installed after November 23, 1968, that exhibit an opacity 

of 20% or greater averaged over 6 consecutive minutes, unless otherwise specified by rule or in 

this permit.

A.4. Pursuant to ARM 17.8.308(1), MDU shall not cause or authorize the production, handling, 

transportation, or storage of any material unless reasonable precautions to control emissions of 

particulate matter are taken. Such emissions of airborne particulate matter from any stationary 

source shall not exhibit an opacity of 20% or greater averaged over 6 consecutive minutes, unless 

otherwise specified by rule or in this permit.

A.5. Pursuant to ARM 17.8.308(2), MDU shall not cause or authorize the use of any street, road or 

parking lot without taking reasonable precautions to control emissions of airborne particulate 

matter, unless otherwise specified by rule or in this permit.

A.6. Pursuant to ARM 17.8.308, MDU shall not operate a construction site or demolition project unless 

reasonable precautions are taken to control emissions of airborne particulate matter. Such 

emissions of airborne particulate matter from any stationary source shall not exhibit an opacity of 

20% or greater averaged over 6 consecutive minutes, unless otherwise specified by rule or in this 

permit.

A.7. Pursuant to ARM 17.8.309, unless otherwise specified by rule or in this permit, MDU shall not 

cause or authorize particulate matter caused by the combustion of fuel to be discharged from any 

stack or chimney into the outdoor atmosphere in excess of the maximum allowable emissions of 

particulate matter for existing fuel burning equipment and new fuel burning equipment calculated 

using the following equations:

For existing fuel burning equipment (installed before November 23, 1968): 

E =0.882 * H-0.1664

For new fuel burning equipment (installed on or after November 23, 1968):

E =1.026 * H-0.233

Where H is the heat input capacity in million BTU (MMBtu) per hour and E is the maximum 

allowable particulate emissions rate in pounds per MMBtu.

A.8. Pursuant to ARM 17.8.310, unless otherwise specified by rule or in this permit, MDU shall not 

cause or authorize particulate matter to be discharged from any operation, process, or activity into 

the outdoor atmosphere in excess of the maximum hourly allowable emissions of particulate 

matter calculated using the following equations:

For process weight rates up to 30 tons per hour: E = 4.10 * P0.67

For process weight rates in excess of 30 tons per hour: E = 55.0 * P0.11– 40

Where E = rate of emissions in pounds per hour and P = process weight rate in tons per hour.

A.9. Pursuant to ARM 17.8.322(4), MDU shall not burn liquid or solid fuels containing sulfur in excess 

of 1 pound per million BTU fired, unless otherwise specified by rule or in this permit.

A.10. Pursuant to ARM 17.8.322(5), MDU shall not burn any gaseous fuel containing sulfur compounds 

in excess of 50 grains per 100 cubic feet of gaseous fuel, calculated as hydrogen sulfide at 

standard conditions, unless otherwise specified by rule or in this permit.
OP0691-05 5 Decision: 11/03/10

Effective Date: 12/04/10

A.11. Pursuant to ARM 17.8.324(3), MDU shall not load or permit the loading of gasoline into any 

stationary tank with a capacity of 250 gallons or more from any tank truck or trailer, except 

through a permanent submerged fill pipe, unless such tank is equipped with a vapor loss control 

device or is a pressure tank as described in ARM 17.8.324(1), unless otherwise specified by rule 

or in this permit.

A.12. Pursuant to ARM 17.8.324, unless otherwise specified by rule or in this permit, MDU shall not 

place, store or hold in any stationary tank, reservoir or other container of more than 65,000 gallon 

capacity any crude oil, gasoline or petroleum distillate having a vapor pressure of 2.5 pounds per 

square inch absolute or greater under actual storage conditions, unless such tank, reservoir or other 

container is a pressure tank maintaining working pressure sufficient at all times to prevent 

hydrocarbon vapor or gas loss to the atmosphere, or is designed and equipped with a vapor loss 

control device, properly installed, in good working order and in operation. 

A.13. Pursuant to ARM 17.8.324, unless otherwise specified by rule or in this permit, MDU shall not 

use any compartment of any single or multiple-compartment oil-effluent water separator, which 

compartment receives effluent water containing 200 gallons a day or more of any petroleum 

product from any equipment processing, refining, treating, storing or handling kerosene or other 

petroleum product of equal or greater volatility than kerosene, unless such compartment is 

equipped with a vapor loss control device, constructed so as to prevent emission of hydrocarbon 

vapors to the atmosphere, properly installed, in good working order and in operation. 

A.14. Pursuant to ARM 17.8.342 and 40 CFR 63.6, MDU shall submit to the Department a copy of any 

startup, shutdown, and malfunction (SSM) plan required under 40 CFR 63.6(e)(3) within 30 days 

of the effective date of this operating permit (if not previously submitted), within 30 days of the 

compliance date of any new National Emission Standard for Hazardous Air Pollutants 

(NESHAPs) or Maximum Achievable Control Technology (MACT) standard, and within 30 days 

of the revision of any such SSM plan, when applicable. The Department requests submittal of 

such plans in electronic form, when possible.

A.15. MDU shall promptly report deviations from permit requirements including those attributable to 

upset conditions, as upset is defined in the permit. To be considered prompt, deviations shall be 

reported to the Department using the schedule and content as described in Section V.E (unless 

otherwise specified in an applicable requirement) (ARM 17.8.1212).

A.16. On or before February 15 and August 15 of each year, MDU shall submit to the Department the 

compliance monitoring reports required by Section V.D. These reports must contain all 

information required by Section V.D, as well as the information required by each individual 

emissions unit. For the reports due by February 15 of each year, MDU may submit a single report, 

provided that it contains all the information required by Section V.B & V.D. Per ARM 17.8.1207, 

any application form, report, or compliance certification submitted 

pursuant to ARM Title 17, Chapter 8, Subchapter 12 (including 

semiannual monitoring reports), shall contain certification by a 

responsible official of truth, accuracy and completeness. This 

certification and any other certification required under ARM Title 17, 

Chapter 8, Subchapter 12, shall state that, “based on information and 

belief formed after reasonable inquiry, the statements and information 

in the document are true, accurate and complete.”
OP0691-05 6 Decision: 11/03/10

Effective Date: 12/04/10

A.17. By February 15 of each year, MDU shall submit to the Department the compliance certification

required by Section V.B. The annual certification required by Section V.B must include a 

statement of compliance based on the information available which identifies any observed, 

documented or otherwise known instance of noncompliance for each applicable requirement. Per 

ARM 17.8.1207,

any application form, report, or compliance certification submitted 

pursuant to ARM Title 17, Chapter 8, Subchapter 12 (including annual 

certifications), shall contain certification by a responsible official of 

truth, accuracy and completeness. This certification and any other 

certification required under ARM Title 17, Chapter 8, Subchapter 12, 

shall state that, “based on information and belief formed after 

reasonable inquiry, the statements and information in the document 

are true, accurate and complete.”

B. EU01: Tangential Coal-Fired Boiler (Coal and Natural Gas)

Condition(s) Pollutant/Parameter Permit Limit

Compliance Demonstration

Method Frequency

Reporting 

Requiremen

ts

B.1, B.11, 

B.12, B.23, 

B.24, B.26, 

B.34, .B35, 

B.36

Opacity 40% Method 9 As Required 

by the 

Department

Semiannual

Predictive 

Opacity

Ongoing Quarterly

B.2, B.13, 

B.23, B.24, 

B.34, .B35, 

B.36

Particulate Matter 

Fuel Burning

0.17 lb/MMBtu Method 5 Annual Semiannual

0.08 gr/dscf

B.3, B.4, 

B.14, B.15, 

B.16, B.25, 

B.27, B.28, 

B.35, B.36

SO2 Emissions 1.0 lb 

sulfur/MMBtu 

fuel or 2.0 lb 

SO2/MMBtu

Continuous 

Scrubber 

Operations and 

CEMS

Ongoing Semiannual

50 gr sulfur/100 

CF fuel

Record

Keeping

Ongoing Semiannual

B.5, B.17, 

B.28, .B35, 

B.36

NOx

Emissions/Acid 

Rain Provisions

0.40 lb/MMBtu CEMS Ongoing Semiannual

B.6, B.18, 

B.29, .B35, 

B.36

Acid Rain 

Provisions

40 CFR 72-78 40 CFR 72-78 40 CFR 72-78 Semiannual

B.7, B.19, 

B.30, .B35, 

B.36

PM CAM Plan ARM 

17.8.1506

Provisions from 

CAM Plan, 

Appendix I

Ongoing Semiannual

B.8, B.20, 

B.31, .B35, 

B.36

Mercury Emissions 1.5 lb/TBtu MEMS Ongoing Semiannual

B.9, B.21, 

B.32, .B35, 

B.36

Mercury Emission 

Control Equipment

OAI and ACI 

Systems

Log Ongoing Semiannual

B.10, B.22, 

B.33, .B35, 

B.36

40 CFR Part 75 40 CFR Part 75 40 CFR Part 75 Ongoing Semiannual
OP0691-05 7 Decision: 11/03/10

Effective Date: 12/04/10

Conditions

B.1. MDU may not cause or authorize emissions from the Tangential Coal-Fired Boiler (boiler) to be 

discharged into the outdoor atmosphere that exhibit an opacity of 40% or greater averaged over 6 

consecutive minutes (ARM 17.8.304 (2)).

B.2. Particulate matter emissions from the boiler shall not exceed 0.17 lb/MMBtu or 0.08 gr/dscf 

(ARM 17.8.309).

B.3. MDU shall not fire in the boiler liquid or solid fuels containing sulfur in excess of 1.0 lb of 

sulfur/MMBtu fuel or 2.0 lb SO2/MMBtu (ARM 17.8.322(4)).

B.4. MDU shall not fire in the boiler any fuels in excess of 50 grains of sulfur/100 cubic feet of 

gaseous fuel (ARM 17.8.322).

B.5. NOX emissions from the boiler shall not exceed 0.40 lb/MMBtu (40 CFR 76.7).

B.6. MDU shall comply with all applicable standards and limitations, and the reporting, 

recordkeeping, and notification requirements of the Acid Rain Program contained in 40 CFR 72-

78 (40 CFR 72-78).

B.7. MDU shall provide a reasonable assurance of compliance with emission limitations or standards 

for the anticipated range of operations at the Tangential Coal-fired Boiler for PM (ARM 

17.8.1504).

B.8. Beginning January 1, 2010, MDU shall limit mercury emissions from Unit 1 to an emission rate 

equal to or less than 1.5 pounds mercury per trillion British thermal units (lb/TBtu), calculated as 

a rolling 12-month average (ARM 17.8.771).

B.9. MDU shall install an oxidizing agent injection (OAI) system and an activated carbon injection 

(ACI) system. MDU shall implement the operation and maintenance of the OAI and ACI 

systems on or before January 1, 2010 (ARM 17.8.771).

B.10. MDU shall comply with all applicable standards and limitations, and the applicable operating, 

reporting, recordkeeping, and notification requirements contained in 40 CFR Part 75 (ARM 

17.8.771).

Compliance Demonstration

B.11. MDU shall perform a Method 9 opacity test on the boiler annually or as required by the 

Department while the boiler is being fired exclusively on coal to monitor compliance with the 

opacity limitation in Section III.B.1 (ARM 17.8.749 and ARM 17.8.106).

B.12. MDU shall operate and maintain the predictive opacity monitoring system to monitor compliance 

with the opacity limitation in Section III.B.1. The monitoring system operation shall be 

performed in accordance with the Predictive Opacity Appendix E of this permit (40 CFR Part 51, 

Appendix P, §3.9 and ARM 17.8.749).

B.13. MDU shall perform a Method 5 or Method 5B particulate matter test, or another method 

approved by the Department, on the boiler annually to monitor compliance with the particulate 

matter fuel burning limit in Section III.B.2. The testing shall be performed in accordance with 

the Montana Source Test Protocol and Procedures Manual while the boiler is being fired 

exclusively on coal (ARM 17.8.749 and ARM 17.8.106).
OP0691-05 8 Decision: 11/03/10

Effective Date: 12/04/10

B.14. MDU shall operate the scrubber when the boiler is operating to monitor compliance with the 

emission limit in III.B.3 (ARM 17.8.322(6)(c)).

B.15. MDU shall monitor compliance with emission limits in III.B.3 pursuant to the requirements in 40 

CFR Part 75, and the SO2 CEMS Appendix F in this permit (ARM 17.8.1212).

B.16. MDU shall burn only pipeline quality natural gas in the emissions unit when burning gaseous fuel 

to monitor compliance with the emission limit of 50 grains of sulfur/100 cf of gaseous fuel (ARM 

17.8.1213).

B.17. MDU shall monitor compliance with emission limits in III.B.5 pursuant to the requirements in 40 

CFR Part 75, 40 CFR Part 76 and the NOX CEMS Appendix G in this permit (ARM 17.8.1212).

B.18. Compliance monitoring for the applicable requirements contained in 40 CFR 72-78 shall be 

accomplished as described in 40 CFR 72-78 (40 CFR 72-78 and ARM 17.8.1213). 

B.19. MDU shall monitor compliance by following the Compliance Assurance Monitoring (CAM) Plan 

(Appendix I). The CAM Plan, written by MDU in accordance with ARM 17.8.1504 is 

summarized in Appendix I and is available in full upon request by the Department or the facility 

(ARM 17.8.1503 and ARM 17.8.1213).

B.20. In order to monitor compliance with the mercury emission limit in III.B.8, a mercury emissions 

monitoring system (MEMS) shall be installed, certified, and operating on the Unit 1 stack outlet 

on or before January 1, 2010. Said monitor shall comply with the applicable provisions of 40 

CFR Part 75. The MEMS shall also conform to requirements included in Appendix J (ARM 

17.8.1213). 

B.21. Monitoring compliance with the requirements for the installation and operation of OAI and ACI 

systems shall be accomplished through recordkeeping (ARM 17.8.1213).

B.22. Compliance monitoring for the operating, reporting, recordkeeping, and notification requirements 

contained in 40 CFR Part 75 shall be accomplished as described in 40 CFR 75 (ARM 17.8.340 

and 40 CFR 75).

Recordkeeping

B.23. MDU shall maintain, on site, an operations and maintenance log which includes the type of fuel 

fired in the boiler on a daily basis (ARM 17.8.1212).

B.24. All source testing recordkeeping shall be performed in accordance with the Source Test Protocol 

and Procedures Manual, and shall be maintained on site. Method 9 source test reports for opacity 

need not be submitted unless requested by the Department (ARM 17.8.106).

B.25. MDU shall maintain, on site, a log of scrubber downtime and maintenance with respect to boiler 

operations (ARM 17.8.1212).

B.26. MDU shall perform recordkeeping in accordance with the Predictive Opacity Monitoring System 

Appendix E of this permit (ARM 17.8.1212).

B.27. MDU shall verify that only pipeline quality natural gas is being burned in the boiler by 

maintaining a log of the Federal Energy Regulatory Commission (FERC) certifications (ARM 

17.8.1212).
OP0691-05 9 Decision: 11/03/10

Effective Date: 12/04/10

B.28. MDU shall perform recordkeeping as required in Appendix F and Appendix G of this permit as 

well as in accordance with 40 CFR Parts 75 and 76, as applicable (ARM 17.8.1212 and 40 CFR 

Parts 75 and 76).

B.29. MDU shall perform recordkeeping in accordance with 40 CFR 72-78, as applicable and as 

required by Appendices G and H of this permit (40 CFR 72-78 and ARM 17.8.1212).

B.30. Records shall be prepared and data kept in accordance with 40 CFR Part 64 and the CAM 

Appendix I of this permit (ARM 17.8.1212 and 40 CFR 64).

B.31. Records shall be prepared and data kept in accordance with 40 CFR Part 75 and the MEMS 

Appendix J of this permit (ARM 17.8.1212 and 40 CFR 75).

B.32. For any time after January 1, 2010, MDU shall record in a log the date, time, and duration of any 

incident where the OAI and ACI systems are not maintained or operational (ARM 17.8.1212).

B.33. MDU shall perform recordkeeping in accordance with 40 CFR Part 75 (ARM 17.8.1212 and 40 

CFR Part75).

Reporting

B.34. Any compliance source tests shall be submitted in accordance with the Montana Source Test 

Protocol and Procedures Manual (ARM 17.8.106).

B.35. The annual compliance certification report required by Section V.B must contain a certification 

statement for the above applicable requirements (ARM 17.8.1212). 

B.36. The semiannual reporting shall provide (ARM 17.8.1212):

a. A summary of results of any source test that was performed during the reporting period;

b. A summary of the log of fuel type used to fire the boiler;

c. A summary of any downtime and maintenance work performed on the wet scrubber; 

d. Certification of submittal of the quarterly reports required in Appendices E, F, G, and J ;

e. A summary of compliance with 40 CFR Part 64 and Appendix I of this permit;

f. A summary of the log when the OAI and ACI systems were not maintained or 

operational: and

g. A summary of compliance with the requirements of 40 CFR 72-78, as applicable.
OP0691-05 10 Decision: 11/03/10

Effective Date: 12/04/10

C. EU06: Fuel (gasoline) Storage Tank

Condition(s) Pollutant/Parameter Permit Limit Compliance Demonstration

 Method Frequency

Reporting 

Requirement

C.1, C.2, C.3, 

C.4, C.5

40 CFR 63, Subpart 

CCCCCC

40 CFR 63, 

Subpart 

CCCCCC

40 CFR 63,

Subpart 

CCCCCC

Ongoing Semiannual

Conditions

C.1. MDU shall comply with all applicable standards and limitations, and the applicable operating, 

reporting, recordkeeping, and notification requirements contained in 40 CFR 63, Subpart 

CCCCCC (ARM 17.8.340 and 40 CFR 63, Subpart CCCCCC).

Compliance Demonstration

C.2. Compliance monitoring for the operating, reporting, recordkeeping, and notification requirements 

contained in 40 CFR 63, Subpart CCCCCC shall be accomplished as described in 40 CFR 63,

Subpart CCCCCC (ARM 17.8.340 and 40 CFR 63, Subpart CCCCCC).

Recordkeeping

C.3. MDU shall perform recordkeeping in accordance with 40 CFR 63, Subpart CCCCCC (ARM 

17.8.1212 and 40 CFR 63, Subpart CCCCCC). 

Reporting

C.4. The annual compliance certification required by Section V.B must contain a certification 

statement for the above applicable requirements (ARM 17.8.1212). 

C.5. The semiannual reporting shall provide a summary of compliance with 40 CFR 63, Subpart 

CCCCCC.

D. EU07: Coal Storage Piles

Condition(s) Pollutant/Parameter Permit Limit Compliance Demonstration

 Method Frequency

Reporting 

Requirement

D.1, D.2, D.3, 

D.4, D.5, D.6, 

D.7, D.8

Opacity 40% and 

Reasonable 

Precautions

Method 9 Semiannual Semiannual

Visual 

Surveys

Once per 

Calendar 

Week

Semiannual

Conditions

D.1. MDU may not cause or authorize emissions from the Coal Storage Piles to be discharged into the 

outdoor atmosphere that exhibit an opacity of 40% or greater averaged over 6 consecutive 

minutes (ARM 17.8.304(1)).

D.2. MDU shall not cause or authorize the production, handling, transportation, or storage of any 

material unless reasonable precautions to control emissions of particulate matter are taken. Such 

emissions of airborne particulate from any stationary source shall not exhibit an opacity of 20% 

or greater averaged over 6 consecutive minutes (ARM 17.8.308(1)).
OP0691-05 11 Decision: 11/03/10

Effective Date: 12/04/10

Compliance Demonstration

D.3 MDU shall conduct either a semiannual Method 9 source test or a weekly visual survey of visible 

emissions on Coal Storage Piles. Under the visual survey option, once per calendar week, during 

daylight hours, MDU shall visually survey Coal Storage Piles for any visible emissions. If visible 

emissions are observed during the visual survey, MDU must take corrective action to contain or 

minimize the source of emissions. Following the corrective action, MDU shall again visually 

survey the Coal Storage Piles for any visible emissions. If visible emissions remain, MDU shall 

conduct a Method 9 source test. The Method 9 source test must begin within one hour of any 

observation of visible emissions following the corrective action. The person conducting the 

visual survey shall record the results of the survey (including any corrective action taken and the 

results of any Method 9 source test performed) in a log, Conducting a visual survey does not 

relieve MDU of the liability for a violation determined using Method 9 (ARM 17.8.101(27)). 

If the visual surveys are not performed once per calendar week as specified above during the 

reporting period, then MDU shall perform the Method 9 source tests on Coal Storage Piles for 

that reporting period. 

Method 9 source tests must be performed in accordance with the Montana Source Test Protocol 

and Procedures Manual, except that prior notification of the test is not required. Each observation 

period must be a minimum of 6 minutes unless any one reading is 20% or greater, then the 

observation period must be a minimum of 20 minutes or until a violation of the standard has been 

documented, whichever is a shorter period of time (ARM 17.8.1213).

Recordkeeping

D.4. All source test recordkeeping shall be performed in accordance with the test method used and the 

Montana Source Test Protocol and Procedures Manual (ARM 17.8.106). 

D.5 If visual surveys are performed, MDU shall maintain a log to verify that the visual surveys were 

performed as specified in Section III.D.3. Each log entry must include the date, time, results of 

survey (and results of subsequent Method 9, if applicable), and observer’s initials If any 

corrective action is required, the time, date, observer’s initials, and any preventive or corrective 

action taken must be recorded in the log (ARM 17.8.1212).

Reporting

D.6. All source test reports must be submitted to the Department in accordance with the Montana 

Source Test Protocol and Procedures Manual (ARM 17.8.106).

D.7. The annual compliance certification report required by Section V.B must contain a certification 

statement for the above applicable requirements (ARM 17.8.1212). 

D.8. The semiannual reporting shall provide (ARM 17.8.1212): 

a. A summary of the visual survey log as required by Section III.D.3 or Method 9 source test 

results, and 

b. A summary of the log of corrective actions maintained as required by Section III.D.5.
OP0691-05 12 Decision: 11/03/10

Effective Date: 12/04/10

E. EU08: Fugitive Coal, Ash, and Lime Handling

Condition(s) Pollutant/Parameter Permit Limit Compliance Demonstration

 Method Frequency

Reporting 

Requirement

E.1, E.2, E.3, 

E.4, E.5, E.6, 

E.7, E.8

Opacity 40% and 

Reasonable 

Precautions

Method 9 Semiannual Semiannual

Visual 

Surveys

Once per 

Calendar 

Week

Semiannual

Conditions

E.1. MDU may not cause or authorize emissions from the fugitive coal, ash, and lime handling to be 

discharged into the outdoor atmosphere that exhibit an opacity of 40% or greater averaged over 6 

consecutive minutes (ARM 17.8.304(1)).

E.2. MDU shall not cause or authorize the production, handling, transportation, or storage of any 

material unless reasonable precautions to control emissions of particulate matter are taken. Such 

emissions of airborne particulate from any stationary source shall not exhibit an opacity of 20% 

or greater averaged over 6 consecutive minutes (ARM 17.8.308(1)).

Compliance Demonstration

E.3 MDU shall conduct either a semiannual Method 9 source test or a weekly visual survey of visible 

emissions on the coal, ash, and lime handling. Under the visual survey option, once per calendar 

week, during daylight hours, MDU shall visually survey the coal, ash, and lime handling for any 

visible emissions. If visible emissions are observed during the visual survey, MDU must take 

corrective action to contain or minimize the source of emissions. Following the corrective action, 

MDU shall again visually survey the coal, ash, and lime handling for any visible emissions. If 

visible emissions remain, MDU shall conduct a Method 9 source test. The Method 9 source test 

must begin within one hour of any observation of visible emissions following the corrective 

action. The person conducting the visual survey shall record the results of the survey (including 

any corrective action taken and the results of any Method 9 source test performed) in a log, 

Conducting a visual survey does not relieve MDU of the liability for a violation determined using 

Method 9 (ARM 17.8.101(27)). 

If the visual surveys are not performed once per calendar week as specified above during the 

reporting period, then MDU shall perform the Method 9 source tests on the coal, ash, and lime 

handling for that reporting period. 

Method 9 source tests must be performed in accordance with the Montana Source Test Protocol 

and Procedures Manual, except that prior notification of the test is not required. Each observation 

period must be a minimum of 6 minutes unless any one reading is 20% or greater, then the 

observation period must be a minimum of 20 minutes or until a violation of the standard has been 

documented, whichever is a shorter period of time (ARM 17.8.1213).

Recordkeeping

E.4. All source test recordkeeping shall be performed in accordance with the test method used and the 

Montana Source Test Protocol and Procedures Manual (ARM 17.8.106). 
OP0691-05 13 Decision: 11/03/10

Effective Date: 12/04/10

E.5. If visual surveys are performed, MDU shall maintain a log to verify that the visual surveys were 

performed as specified in Section III.E.3. Each log entry must include the date, time, results of 

survey (and results of subsequent Method 9, if applicable), and observer’s initials If any 

corrective action is required, the time, date, observer’s initials, and any preventive or corrective 

action taken must be recorded in the log (ARM 17.8.1212).

Reporting

E.6. All source test reports must be submitted to the Department in accordance with the Montana 

Source Test Protocol and Procedures Manual (ARM 17.8.106).

E.7. The annual compliance certification report required by Section V.B must contain a certification 

statement for the above applicable requirements (ARM 17.8.1212). 

E.8. The semiannual reporting shall provide (ARM 17.8.1212): 

a. A summary of the visual survey log as required by Section III.E.3 or Method 9 source 

test results; and

b. A summary of the log of corrective actions maintained as specified by Section III.E.5.
OP0691-05 14 Decision: 11/03/10

Effective Date: 12/04/10

SECTION IV. NON-APPLICABLE REQUIREMENTS

Air Quality Administrative Rules of Montana (ARM) and Federal Regulations identified as not applicable 

to the facility or to a specific emissions unit at the time of the permit issuance are listed below (ARM 

17.8.1214). The following list does not preclude the need to comply with any new requirements that may 

become applicable during the permit term.

A. Facility-Wide

The following table contains non-applicable requirements which are administrated by the Air Resources 

Management Bureau of the Department of Environmental Quality.

Rule Citation Reason

State Federal

ARM 17.8.321, ARM 

17.8.323, ARM 17.8.610

These rules are not applicable because the facility is not 

listed in the source category cited in the rules.

ARM 17.8.320 These rules are not applicable because the facility does not 

have the specific emissions unit cited in the rules.

40 CFR 60, Subparts C, Ca, Cb

40 CFR 60, Subparts D, Da, Db, Dc

40 CFR 60, Subparts E-J

40 CFR 60, Subparts K, Ka, Kb 

40 CFR 60, Subparts L-Z

40 CFR 60, Subparts AA-EE

40 CFR 60, Subparts GG-HH

40 CFR 60, Subparts KK-NN

40 CFR 60, Subparts PP-XX

40 CFR 60, Subparts AAA-BBB

40 CFR 60, Subpart DDD

40 CFR 60, Subparts FFF-LLL

40 CFR 60, Subparts NNN-VVV

40 CFR 60, Subpart WWW

40 CFR 60, Subparts AAAA-FFFF

40 CFR 60, Subparts IIII-KKKK

40 CFR 61, Subparts B-F

40 CFR 61, Subparts H-L

40 CFR 61, Subparts N-R

40 CFR 61, Subpart T

40 CFR 61, Subparts V-W

40 CFR 61, Subpart Y

40 CFR 61, Subpart BB

40 CFR 61, Subpart FF

These requirements are not applicable because the facility 

is not an affected source as defined in these regulations.

40 CFR 63, Subparts F-I

40 CFR 63, Subpart J

40 CFR 63, Subparts L-Q

40 CFR 63, Subparts Q-U

40 CFR 63, Subparts W-Y

40 CFR 63, Subparts AA-EE

40 CFR 63, Subparts GG-MM

40 CFR 63, Subparts OO-YY

40 CFR 63, Subparts CCC-EEE

40 CFR 63, Subparts GGG-JJJ

40 CFR 63, Subparts LLL-RRR

These requirements are not applicable because the facility 

is not an affected source as defined in these regulations.
OP0691-05 15 Decision: 11/03/10

Effective Date: 12/04/10

Rule Citation Reason

State Federal

40 CFR 63, Subparts TTT-VVV

40 CFR 63, Subpart XXX

40 CFR 63, Subpart AAAA

40 CFR 63, Subparts CCCC-KKKK

40 CFR 63, Subparts MMMMNNNNN

40 CFR 63, Subparts PPPPP-TTTTT

40 CFR 63, Subpart WWWWW

40 CFR 63, Subparts YYYYYZZZZZ

40 CFR 63, Subpart BBBBBB

40 CFR 63, Subparts DDDDDDHHHHHH

40 CFR 63, Subparts LLLLLLTTTTTT

40 CFR 63, Subparts WWWWWWXXXXXX

40 CFR 82, Subparts A-E

40 CFR 82, Subparts G-H

B. Emission Units

The Operating Permit #OP0691-04 renewal application identified applicable and non-applicable 

requirements. After review of the application, the Department listed all non-applicable requirements in 

Section IV.A. These requirements relate to each specific unit, as well as facility wide.
OP0691-05 16 Decision: 11/03/10

Effective Date: 12/04/10

SECTION V. GENERAL PERMIT CONDITIONS

A. Compliance Requirements

ARM 17.8, Subchapter 12, Operating Permit Program §1210(2)(a)-(c)&(e), §1206(6)(c)&(b)

1. The permittee must comply with all conditions of the permit. Any noncompliance with the 

terms or conditions of the permit constitutes a violation of the Montana Clean Air Act, and may 

result in enforcement action, permit modification, revocation and reissuance, or termination, or 

denial of a permit renewal application under ARM Title 17, Chapter 8, Subchapter 12.

2. The filing of a request by the permittee for a permit modification, revocation and reissuance, or 

termination, or of a notification of planned changes or anticipated noncompliance does not stay 

any permit condition.

3. It shall not be a defense for a permittee in an enforcement action that it would have been 

necessary to halt or reduce the permitted activity in order to maintain compliance with the 

conditions of the permit. If appropriate, this factor may be considered as a mitigating factor in 

assessing a penalty for noncompliance with an applicable requirement if the source 

demonstrates that both the health, safety or environmental impacts of halting or reducing 

operations would be more serious than the impacts of continuing operations, and that such 

health, safety or environmental impacts were unforeseeable and could not have otherwise been 

avoided.

4. The permittee shall furnish to the Department, within a reasonable time set by the Department 

(not to be less than 15 days), any information that the Department may request in writing to 

determine whether cause exists for modifying, revoking and reissuing, or terminating the 

permit, or to determine compliance with the permit. Upon request, the permittee shall also 

furnish to the Department copies of those records that are required to be kept pursuant to the 

terms of the permit. This subsection does not impair or otherwise limit the right of the 

permittee to assert the confidentiality of the information requested by the Department, as 

provided in 75-2-105, MCA.

5. Any schedule of compliance for applicable requirements with which the source is not in 

compliance with at the time of permit issuance shall be supplemental to, and shall not sanction 

noncompliance with, the applicable requirements on which it was based.

6. For applicable requirements that will become effective during the permit term, the source shall 

meet such requirements on a timely basis unless a more detailed plan or schedule is required by 

the applicable requirement or the Department.

B. Certification Requirements

ARM 17.8, Subchapter 12, Operating Permit Program §1207 and §1213(7)(a)&(c)-(d)

1. Any application form, report, or compliance certification submitted pursuant to ARM Title 17, 

Chapter 8, Subchapter 12, shall contain certification by a responsible official of truth, accuracy 

and completeness. This certification and any other certification required under ARM Title 17, 

Chapter 8, Subchapter 12, shall state that, based on information and belief formed after 

reasonable inquiry, the statements and information in the document are true, accurate and 

complete.
OP0691-05 17 Decision: 11/03/10

Effective Date: 12/04/10

2. Compliance certifications shall be submitted by February 15 of each year, or more frequently if 

otherwise specified in an applicable requirement or elsewhere in the permit. Each certification 

must include the required information for the previous calendar year (i.e., January 1 –

December 31).

3. Compliance certifications shall include the following:

a. The identification of each term or condition of the permit that is the basis of the 

certification;

b. The identification of the method(s) or other means used by the owner or operator for 

determining the status of compliance with each term and condition during the certification 

period, consistent with ARM 17.8.1212;

c. The status of compliance with each term and condition for the period covered by the 

certification, including whether compliance during the period was continuous or 

intermittent (based on the method or means identified in ARM 17.8.1213(7)(c)(ii), as 

described above); and

d. Such other facts as the Department may require to determine the compliance status of the 

source.

4. All compliance certifications must be submitted to the Environmental Protection Agency, as 

well as to the Department, at the addresses listed in the Notification Addresses Appendix of this 

permit.

C. Permit Shield

ARM 17.8, Subchapter 12, Operating Permit Program §1214(1)-(4)

1. The applicable requirements and non-federally enforceable requirements are included and 

specifically identified in this permit and the permit includes a precise summary of the 

requirements not applicable to the source. Compliance with the conditions of the permit shall 

be deemed compliance with any applicable requirements and any non-federally enforceable 

requirements as of the date of permit issuance.

2. The permit shield described in 1 above shall remain in effect during the appeal of any permit 

action (renewal, revision, reopening, or revocation and reissuance) to the Board of 

Environmental Review (Board), until such time as the Board renders its final decision.

3. Nothing in this permit alters or affects the following:

a. The provisions of Sec. 7603 of the FCAA, including the authority of the administrator 

under that section;

b. The liability of an owner or operator of a source for any violation of applicable 

requirements prior to or at the time of permit issuance;

c. The applicable requirements of the Acid Rain Program, consistent with Sec. 7651g(a) of 

the FCAA;

d. The ability of the administrator to obtain information from a source pursuant to Sec. 7414 

of the FCAA;
OP0691-05 18 Decision: 11/03/10

Effective Date: 12/04/10

e. The ability of the Department to obtain information from a source pursuant to the Montana 

Clean Air Act, Title 75, Chapter 2, MCA;

f. The emergency powers of the Department under the Montana Clean Air Act, Title 75, 

Chapter 2, MCA; and

g. The ability of the Department to establish or revise requirements for the use of Reasonably 

Available Control Technology (RACT) as defined in ARM Title 17, Chapter 8. However, 

if the inclusion of a RACT into the permit pursuant to ARM Title 17, Chapter 8, 

Subchapter 12, is appealed to the Board, the permit shield, as it applies to the source’s 

existing permit, shall remain in effect until such time as the Board has rendered its final 

decision.

4. Nothing in this permit alters or affects the ability of the Department to take enforcement action 

for a violation of an applicable requirement or permit term demonstrated pursuant to ARM 

17.8.106, Source Testing Protocol.

5. Pursuant to ARM 17.8.132, for the purpose of submitting a compliance certification, nothing in 

these rules shall preclude the use, including the exclusive use, of any credible evidence or 

information relevant to whether a source would have been in compliance. However, when 

compliance or noncompliance is demonstrated by a test or procedure provided by permit or 

other applicable requirements, the source shall then be presumed to be in compliance or 

noncompliance unless that presumption is overcome by other relevant credible evidence.

6. The permit shield will not extend to minor permit modifications or changes not requiring a 

permit revision (see Sections I & J).

7. The permit shield will extend to significant permit modifications and transfer or assignment of

ownership (see Sections K & O).

D. Monitoring, Recordkeeping, and Reporting Requirements

ARM 17.8, Subchapter 12, Operating Permit Program §1212(2)&(3)

1. Unless otherwise provided in this permit, the permittee shall maintain compliance monitoring 

records that include the following information:

a. The date, place as defined in the permit, and time of sampling or measurement;

b. The date(s) analyses were performed;

c. The company or entity that performed the analyses;

d. The analytical techniques or methods used;

e. The results of such analyses; and

f. The operating conditions at the time of sampling or measurement.

2. The permittee shall retain records of all required monitoring data and support information for a 

period of at least 5 years from the date of the monitoring sample, measurement, report, or 

application. Support information includes all calibration and maintenance records and all 

original strip-chart recordings for continuous monitoring instrumentation, and copies of all 

reports required by the permit. All monitoring data, support information, and required reports 
OP0691-05 19 Decision: 11/03/10

Effective Date: 12/04/10

and summaries may be maintained in computerized form at the plant site if the information is 

made available to Department personnel upon request, which may be for either hard copies or 

computerized format. Strip-charts must be maintained in their original form at the plant site 

and shall be made available to Department personnel upon request.

3. The permittee shall submit to the Department, at the addresses located in the Notification 

Addresses Appendix of this permit, reports of any required monitoring by February 15 and 

August 15 of each year, or more frequently if otherwise specified in an applicable requirement 

or elsewhere in the permit. The monitoring report submitted on February 15 of each year must

include the required monitoring information for the period of July 1 through December 31 of 

the previous year. The monitoring report submitted on August 15 of each year must include the 

required monitoring information for the period of January 1 through June 30 of the current year. 

All instances of deviations from the permit requirements must be clearly identified in such 

reports. All required reports must be certified by a responsible official, consistent with ARM 

17.8.1207.

E. Prompt Deviation Reporting

ARM 17.8, Subchapter 12, Operating Permit Program §1212(3)(c)

The permittee shall promptly report deviations from permit requirements, including those attributable 

to upset conditions as defined in the permit, the probable cause of such deviations, and any corrective 

actions or preventive measures taken. To be considered prompt, deviations shall be reported to the 

Department within the following timeframes (unless otherwise specified in an applicable 

requirement):

1. For deviations which may result in emissions potentially in violation of permit limitations:

a. An initial phone notification (or faxed or electronic notification) describing the incident 

within 24 hours (or the next business day) of discovery; and,

b. A follow-up written, faxed, or electronic report within 30 days of discovery of the deviation 

that describes the probable cause of the reported deviation and any corrective actions or 

preventative measures taken.

2. For deviations attributable to malfunctions, deviations shall be reported to the Department in 

accordance with the malfunction reporting requirements under ARM 17.8.110; and

3. For all other deviations, deviations shall be reported to the Department via a written, faxed, or 

electronic report within 90 days of discovery (as determined through routine internal review by 

the permittee).

Prompt deviation reports do not need to be resubmitted with regular semiannual (or other routine) 

reports, but may be referenced by the date of submittal.

F. Emergency Provisions

ARM 17.8, Subchapter 12, Operating Permit Program §1201(13) and §1214(5), (6)&(8)

1. An “emergency” means any situation arising from sudden and reasonably unforeseeable events 

beyond the control of the source, including acts of God, which situation requires immediate 

corrective action to restore normal operation and causes the source to exceed a technologybased emission limitation under this permit due to the unavoidable increases in emissions 

attributable to the emergency. An emergency shall not include noncompliance to the extent 

caused by improperly designed equipment, lack of reasonable preventive maintenance, careless 

or improper operation, or operator error.
OP0691-05 20 Decision: 11/03/10

Effective Date: 12/04/10

2. An emergency constitutes an affirmative defense to an action brought for noncompliance with a 

technology-based emission limitation if the permittee demonstrates through properly signed, 

contemporaneous logs, or other relevant evidence, that:

a. An emergency occurred and the permittee can identify the cause(s) of the emergency;

b. The permitted facility was at the time being properly operated;

c. During the period of the emergency the permittee took all reasonable steps to minimize 

levels of emissions that exceeded the emission standards or other requirements in the 

permit; and 

d. The permittee submitted notice of the emergency to the Department within 2 working days 

of the time when emission limitations were exceeded due to the emergency. This notice 

fulfills the requirements of ARM 17.8.1212(3)(c). This notice must contain a description 

of the emergency, any steps taken to mitigate emissions, and corrective actions taken.

3. These emergency provisions are in addition to any emergency, malfunction or upset provision 

contained in any applicable requirement.

G. Inspection and Entry

ARM 17.8, Subchapter 12, Operating Permit Program §1213(3)&(4)

1. Upon presentation of credentials and other requirements as may be required by law, the 

permittee shall allow the Department, the administrator, or an authorized representative 

(including an authorized contractor acting as a representative of the Department or the 

administrator) to perform the following:

a. Enter the premises where a source required to obtain a permit is located or emissionsrelated activity is conducted, or where records must be kept under the conditions of the 

permit;

b. Have access to and copy, at reasonable times, any records that must be kept under the 

conditions of the permit;

c. Inspect at reasonable times any facilities, emission units, equipment (including monitoring 

and air pollution control equipment), practices, or operations regulated or required under 

the permit; and

d. As authorized by the Montana Clean Air Act and rules promulgated thereunder, sample or 

monitor, at reasonable times, any substances or parameters at any location for the purpose 

of assuring compliance with the permit or applicable requirements.

2. The permittee shall inform the inspector of all workplace safety rules or requirements at the 

time of inspection. This section shall not limit in any manner the Department’s statutory right 

of entry and inspection as provided for in 75-2-403, MCA.

H. Fee Payment

ARM 17.8, Subchapter 12, Operating Permit Program §1210(2)(f) and ARM 17.8, Subchapter 5, Air 

Quality Permit Application, Operation, and Open Burning Fees §505(3)-(5) (STATE ONLY)

1. The permittee must pay application and operating fees, pursuant to ARM Title 17, Chapter 8, 

Subchapter 5.
OP0691-05 21 Decision: 11/03/10

Effective Date: 12/04/10

2. Annually, the Department shall provide the permittee with written notice of the amount of the 

fee and the basis for the fee assessment. The air quality operation fee is due 30 days after 

receipt of the notice, unless the fee assessment is appealed pursuant to ARM 17.8.511. If any 

portion of the fee is not appealed, that portion of the fee that is not appealed is due 30 days after 

receipt of the notice. Any remaining fee, which may be due after the completion of an appeal, 

is due immediately upon issuance of the Board’s decision or upon completion of any judicial 

review of the Board’s decision.

3. If the permittee fails to pay the required fee (or any required portion of an appealed fee) within 

90 days of the due date of the fee, the Department may impose an additional assessment of 15% 

of the fee (or any required portion of an appealed fee) or $100, whichever is greater, plus 

interest on the fee (or any required portion of an appealed fee), computed at the interest rate 

established under 15-31-510(3), MCA.

I. Minor Permit Modifications

ARM 17.8, Subchapter 12, Operating Permit Program §1226(3)&(11)

1. An application for a minor permit modification need only address in detail those portions of the 

permit application that require revision, updating, supplementation, or deletion, and may 

reference any required information that has been previously submitted.

2. The permit shield under ARM 17.8.1214 will not extend to any minor modifications processed 

pursuant to ARM 17.8.1226.

J. Changes Not Requiring Permit Revision

ARM 17.8, Subchapter 12, Operating Permit Program §1224(1)-(3), (5)&(6)

1. The permittee is authorized to make changes within the facility as described below, provided 

the following conditions are met:

a. The proposed changes do not require the permittee to obtain a Montana Air Quality Permit

under ARM Title 17, Chapter 8, Subchapter 7;

b. The proposed changes are not modifications under Title I of the FCAA, or as defined in 

ARM Title 17, Chapter 8, Subchapters 8, 9, or 10;

c. The emissions resulting from the proposed changes do not exceed the emissions allowable 

under this permit, whether expressed as a rate of emissions or in total emissions;

d. The proposed changes do not alter permit terms that are necessary to enforce applicable 

emission limitations on emission units covered by the permit; and

e. The facility provides the administrator and the Department with written notification at least 

7 days prior to making the proposed changes.

2. The permittee and the Department shall attach each notice provided pursuant to 1.e above to 

their respective copies of this permit.

3. Pursuant to the conditions above, the permittee is authorized to make Section 502(b)(10) 

changes, as defined in ARM 17.8.1201(30), without a permit revision. For each such change, 

the written notification required under 1.e above shall include a description of the change 

within the source, the date on which the change will occur, any change in emissions, and any 

permit term or condition that is no longer applicable as a result of the change.
OP0691-05 22 Decision: 11/03/10

Effective Date: 12/04/10

4. The permittee may make a change not specifically addressed or prohibited by the permit terms 

and conditions without requiring a permit revision, provided the following conditions are met:

a. Each proposed change does not weaken the enforceability of any existing permit 

conditions;

b. The Department has not objected to such change;

c. Each proposed change meets all applicable requirements and does not violate any existing 

permit term or condition; and

d. The permittee provides contemporaneous written notice to the Department and the 

administrator of each change that is above the level for insignificant emission units as 

defined in ARM 17.8.1201(22) and 17.8.1206(3), and the written notice describes each 

such change, including the date of the change, any change in emissions, pollutants emitted, 

and any applicable requirement that would apply as a result of the change.

5. The permit shield authorized by ARM 17.8.1214 shall not apply to changes made pursuant to 

ARM 17.8.1224(3) and (5), but is applicable to terms and conditions that allow for increases 

and decreases in emissions pursuant to ARM 17.8.1224(4).

K. Significant Permit Modifications

ARM 17.8, Subchapter 12, Operating Permit Program §1227(1), (3)&(4)

1. The modification procedures set forth in 2 below must be used for any application requesting a 

significant modification of this permit. Significant modifications include the following:

a. Any permit modification that does not qualify as either a minor modification or as an 

administrative permit amendment;

b. Every significant change in existing permit monitoring terms or conditions;

c. Every relaxation of permit reporting or recordkeeping terms or conditions that limit the 

Department’s ability to determine compliance with any applicable rule, consistent with the 

requirements of the rule; or

d. Any other change determined by the Department to be significant.

2. Significant modifications shall meet all requirements of ARM Title 17, Chapter 8, including 

those for applications, public participation, and review by affected states and the administrator, 

as they apply to permit issuance and renewal, except that an application for a significant permit 

modification need only address in detail those portions of the permit application that require 

revision, updating, supplementation or deletion.

3. The permit shield provided for in ARM 17.8.1214 shall extend to significant modifications.

L. Reopening for Cause

ARM 17.8, Subchapter 12, Operating Permit Program §1228(1)&(2)

This permit may be reopened and revised under the following circumstances:

1. Additional applicable requirements under the FCAA become applicable to the facility when the 

permit has a remaining term of 3 or more years. Reopening and revision of the permit shall be 

completed not later than 18 months after promulgation of the applicable requirement. No 

reopening is required under ARM 17.8.1228(1)(a) if the effective date of the applicable 
OP0691-05 23 Decision: 11/03/10

Effective Date: 12/04/10

requirement is later than the date on which the permit is due to expire, unless the original 

permit or any of its terms or conditions have been extended pursuant to ARM 17.8.1220(12) or 

17.8.1221(2);

2. Additional requirements (including excess emission requirements) become applicable to an 

affected source under the Acid Rain Program. Upon approval by the administrator, excess 

emission offset plans shall be deemed incorporated into the permit;

3. The Department or the administrator determines that the permit contains a material mistake or 

that inaccurate statements were made in establishing the emission standards or other terms or 

conditions of the permit; or

4. The administrator or the Department determines that the permit must be revised or revoked and 

reissued to ensure compliance with the applicable requirements.

M. Permit Expiration and Renewal

ARM 17.8, Subchapter 12, Operating Permit Program §1210(2)(g), §1220(11)&(12), and §1205(2)(d)

1. This permit is issued for a fixed term of 5 years.

2. Renewal of this permit is subject to the same procedural requirements that apply to permit 

issuance, including those for application, content, public participation, and affected state and 

administrator review.

3. Expiration of this permit terminates the permittee’s right to operate unless a timely and 

administratively complete renewal application has been submitted consistent with ARM 

17.8.1221 and 17.8.1205(2)(d). If a timely and administratively complete application has been 

submitted, all terms and conditions of the permit, including the application shield, remain in 

effect after the permit expires until the permit renewal has been issued or denied.

4. For renewal, the permittee shall submit a complete air quality operating permit application to 

the Department not later than 6 months prior to the expiration of this permit, unless otherwise 

specified. If necessary to ensure that the terms of the existing permit will not lapse before 

renewal, the Department may specify, in writing to the permittee, a longer time period for 

submission of the renewal application. Such written notification must be provided at least 1 

year before the renewal application due date established in the existing permit.

N. Severability Clause

ARM 17.8, Subchapter 12, Operating Permit Program §1210(2)(i)&(l)

1. The administrative appeal or subsequent judicial review of the issuance by the Department of 

an initial permit under this subchapter shall not impair in any manner the underlying 

applicability of all applicable requirements, and such requirements continue to apply as if a 

final permit decision had not been reached by the Department.

2. If any provision of a permit is found to be invalid, all valid parts that are severable from the 

invalid part remain in effect. If a provision of a permit is invalid in one or more of its 

applications, the provision remains in effect in all valid applications that are severable from the 

invalid applications.
OP0691-05 24 Decision: 11/03/10

Effective Date: 12/04/10

O. Transfer or Assignment of Ownership

ARM 17.8, Subchapter 12, Operating Permit Program §1225(2)&(4)

1. If an administrative permit amendment involves a change in ownership or operational control, 

the applicant must include in its request to the Department a written agreement containing a 

specific date for the transfer of permit responsibility, coverage and liability between the current 

and new permittee.

2. The permit shield provided for in ARM17.8.1214 shall not extend to administrative permit 

amendments.

P. Emissions Trading, Marketable Permits, Economic Incentives

ARM 17.8, Subchapter 12, Operating Permit Program §1226(2)

Notwithstanding ARM 17.8.1226(1) and (7), minor air quality operating permit modification 

procedures may be used for permit modifications involving the use of economic incentives, 

marketable permits, emissions trading, and other similar approaches, to the extent that such minor 

permit modification procedures are explicitly provided for in the Montana State Implementation Plan 

or in applicable requirements promulgated by the administrator.

Q. No Property Rights Conveyed

ARM 17.8, Subchapter 12, Operating Permit Program §1210(2)(d)

This permit does not convey any property rights of any sort, or any exclusive privilege.

R. Testing Requirements

ARM 17.8, Subchapter 1, General Provisions §105

The permittee shall comply with ARM 17.8.105.

S. Source Testing Protocol

ARM 17.8, Subchapter 1, General Provisions §106

The permittee shall comply with ARM 17.8.106.

T. Malfunctions

ARM 17.8, Subchapter 1, General Provisions §110

The permittee shall comply with ARM 17.8.110.

U. Circumvention

ARM 17.8, Subchapter 1, General Provisions §111

The permittee shall comply with ARM 17.8.111.

V. Motor Vehicles

ARM 17.8, Subchapter 3, Emission Standards §325

The permittee shall comply with ARM 17.8.325.
OP0691-05 25 Decision: 11/03/10

Effective Date: 12/04/10

W. Annual Emissions Inventory

ARM 17.8, Subchapter 5, Air Quality Permit Application, Operation and Open Burning Fees §505 

(STATE ONLY)

The permittee shall supply the Department with annual production and other information for all 

emission units necessary to calculate actual or estimated actual amount of air pollutants emitted 

during each calendar year. Information shall be gathered on a calendar-year basis and submitted to 

the Department by the date required in the emission inventory request, unless otherwise specified in 

this permit. Information shall be in the units required by the Department.

X. Open Burning

ARM 17.8, Subchapter 6, Open Burning §604, 605 and 606

The permittee shall comply with ARM 17.8.604, 605 and 606.

Y. Montana Air Quality Permits

ARM 17.8, Subchapter 7, Permit, Construction and Operation of Air Contaminant Sources §745 and 

764 (ARM 17.8.745(1) and 764(1)(b) are STATE ENFORCEABLE ONLY until approval by the 

EPA as part of the SIP)

1. Except as specified, no person shall construct, install, modify or use any air contaminant source 

or stack associated with any source without first obtaining a permit from the Department or 

Board. A permit is not required for those sources or stacks as specified by ARM 

17.8.744(1)(a)-(k).

2. The permittee shall comply with ARM 17.8.743, 744, 745, 748, and 764.

3. ARM 17.8.745(1) specifies de minimis changes as construction or changed conditions of 

operation at a facility holding a Montana Air Quality Permit (MAQP) issued under Chapter 8 

that does not increase the facility’s potential to emit by more than 15 tons per year of any 

pollutant, except (STATE ENFORCEABLE ONLY until approved by the EPA as part of the 

SIP):

a. Any construction or changed condition that would violate any condition in the facility’s 

existing MAQP or any applicable rule contained in Chapter 8 is prohibited, except as 

provided in ARM 17.8.745(2);

b. Any construction or changed conditions of operation that would qualify as a major 

modification under Subchapters 8, 9 or 10 of Chapter 8;

c. Any construction or changed condition of operation that would affect the plume rise or 

dispersion characteristic of emissions that would cause or contribute to a violation of an 

ambient air quality standard or ambient air increment as defined in ARM 17.8.804;

d. Any construction or improvement project with a potential to emit more than 15 tons per 

year may not be artificially split into smaller projects to avoid Montana Air Quality 

Permitting; or

e. Emission reductions obtained through offsetting within a facility are not included when 

determining the potential emission increase from construction or changed conditions of 

operation, unless such reductions are made federally enforceable.
OP0691-05 26 Decision: 11/03/10

Effective Date: 12/04/10

4. Any facility making a de minimis change pursuant to ARM 17.8.745(1) shall notify the 

Department if the change would include a change in control equipment, stack height, stack 

diameter, stack gas temperature, source location or fuel specifications, or would result in an 

increase in source capacity above its permitted operation or the addition of a new emission unit. 

The notice must be submitted, in writing, 10 days prior to start up or use of the proposed de 

minimis change, or as soon as reasonably practicable in the event of an unanticipated 

circumstance causing the de minimis change, and must include the information requested in 

ARM 17.8.745(1) (STATE ENFORCEABLE ONLY until approval by the EPA as part of the 

SIP).

Z. National Emission Standard for Asbestos

40 CFR, Part 61, Subpart M

The permittee shall not conduct any asbestos abatement activities except in accordance with 40 CFR 

61, Subpart M (National Emission Standard for Hazardous Air Pollutants for Asbestos).

AA. Asbestos

ARM 17.74, Subchapter 3, General Provisions and Subchapter 4, Fees

The permittee shall comply with ARM 17.74.301, et seq., and ARM 17.74.401, et seq. (State only)

BB.Stratospheric Ozone Protection – Servicing of Motor Vehicle Air Conditioners

40 CFR, Part 82, Subpart B

If the permittee performs a service on motor vehicles and this service involves ozone-depleting 

substance/refrigerant in the motor vehicle air conditioner (MVAC), the permittee is subject to all the 

applicable requirements as specified in 40 CFR 82, Subpart B.

CC. Stratospheric Ozone Protection – Recycling and Emission Reductions

40 CFR, Part 82, Subpart F

The permittee shall comply with the standards for recycling and emission reductions in 40 CFR 82, 

Subpart F, except as provided for MVACs in Subpart B:

1. Persons opening appliances for maintenance, service, repair, or disposal must comply with the 

required practices pursuant to §82.156;

2. Equipment used during the maintenance, service, repair or disposal of appliances must comply 

with the standards for recycling and recovery equipment pursuant to §82.158;

3. Persons performing maintenance, service, repair or disposal of appliances must be certified by 

an approved technical certification program pursuant to §82.161;

4. Persons disposing of small appliances, MVACs and MVAC-like (as defined at §82.152) 

appliances must comply with recordkeeping requirements pursuant to §82.166;

5. Persons owning commercial or industrial process refrigeration equipment must comply with the 

leak repair requirements pursuant to §82.156; and

6. Owners/operators of appliances normally containing 50 or more pounds of refrigerant must 

keep records of refrigerant purchased and added to such appliances pursuant to §82.166.
OP0691-05 27 Decision: 11/03/10

Effective Date: 12/04/10

DD. Emergency Episode Plan

The permittee shall comply with the requirements contained in Chapter 9.7 of the State of Montana 

Air Quality Control Implementation Plan.

Each major source emitting 100 tons per year located in a Priority I Air Quality Control Region, shall 

submit to the Department a legally enforceable Emergency Episode Action Plan (EEAP) that details 

how the source will curtail emissions during an air pollutant emergency episode. The industrial 

EEAP shall be in accordance with the Department’s EEAP and shall be submitted according to a 

timetable developed by the Department, following Priority I reclassification.

EE.Definitions

Terms not otherwise defined in this permit or in the Definitions and Abbreviations Appendix of this 

permit, shall have the meaning assigned to them in the referenced regulations.
Appendix C.1

Control Cost Worksheets
6/3/2011

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

Summary Table Page 1 of 1

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-1 : Control Cost Summary

SO2 Control Cost Summary 

Control Technology

Controled lb 

SO2/MMBtu

Controlled 

Emissions T/y 

Emission 

Reduction T/yr 

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost $/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Non-Air Env 

Impacts?

Spray Dryer Absorber and 

Baghouse 0.08 151.8 850.3 $66,336,000 $10,055,057 $11,825 $13,220 None Medium Solid Waste

Existing Wet Scrubber 0.45 901.9 100.2 $270,000 $138,637 $1,383 NA None Low Waste-water

Dry Sorbent Injection and 

Baghouse 0.45 901.9 100.2 $15,746,000 $2,840,734 $28,347 NA None Medium Solid Waste

Baseline 0.50 1002.1

NOx Control Cost Summary

Control Technology

Controled lb 

NOx/MMBtu

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost $/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Non-Air Env 

Impacts?

Selective Catalytic Reduction 0.04 80.2 721.5 $38,976,000 $6,984,376 $9,680 $18,368 Ammonia Slip Medium

Ammonia in 

Wastewater 

Discharge

SNCR + Low NOx Burners 

with SOFA 0.20 400.9 400.9 $4,531,000 $1,093,962 $2,729 $7,279

Ammonia 

Slip, Higher 

CO Emissions

Low

Ammonia in 

Wastewater 

Discharge

Selective Non Catalytic 

Reduction 0.25 501.1 300.6 $2,433,000 $761,654 $2,533 NA Ammonia Slip Low

Ammonia in 

Wastewater 

Discharge

Low NOx Burners with SOFA 0.25 501.1 300.6 $2,195,000 $364,546 $1,213 NA Higher CO 

Emissions None None

Baseline 0.40 801.7
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

Utility Chem$ Data 6/3/2011 Page 1 of 1

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-2 : Labor, Chemical and Utility Costs

Operating Unit: NA Study Year 2011

Reference

Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 33.5 $/hr 2006 Heskett Unit II BART Report

Maintenance Labor 33.5 $/hr 2006 Heskett Unit II BART Report

Electricity 0.057 $/kwh 0.049 2006 Heskett Unit II BART Report http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005

Average natural gas spot price July 04 - 

June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig 

Water 1.16 $/mgal 1.00 2006 Heskett Unit II BART Report cost adjusted for 3% inflation

Cooling Water 0.32 $/mgal 0.23 1999

EPA Air Pollution Control Cost Manual, 6th 

ed. Section 3.1 Ch 1

Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 

3% inflation

Compressed Air 0.37 $/mscf 0.25 1998

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 6 Chapter 1 

Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% 

inflation

Wastewater Disposal Neutralization 1.96 $/mgal 1.50 2002

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 

Ch 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.96 $/mgal 3.80 2002

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 5.2 Chapter 1

Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost 

adjusted for 3% inflation

Solid Waste Disposal 32.62 $/ton 25.00 2002

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3% 

inflation

Hazardous Waste Disposal 326.19 $/ton 250.00 2002

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3% 

inflation

Waste Transport 0.65 $/ton-mi 0.50 2002

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation

$/ton

Chemicals & Supplies

Lime 0.00 $/ton 2006

Caustic 334.33 $/ton 280 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery

Ammonia 483.59 $/ton 405 2005 Heskett Unit II BART Report 50% solution of urea in water, includes delivery

Hydrated Lime 290.00 $/ton 290.00 2011 MDU data, Feb 9, 2011 email from George Gasper at Lewis and Clark Station

Trona 158.45 Mscf 145 2008 Solvay Chemical cost adjusted for 3% inflation

Urea 50% Solution 637.60 $/ton 550.00 2006 Heskett Unit II BART Report

Aqua Ammonia 0.70 $/lb 0.70 2011 Barr Engineering Data $1,400/NH3 neat delivered at 19% aqua ammonia

Limestone 68.96 $/ton 65.00 2009 MDU 2009 Reagent Study 

NA

Catalyst & Replacement Parts 

SCR Catalyst 214 $/ft3

CO Catalyst 650 $/ft3 Vendor quote if needed

Catalyst #3 $/ft3

Catalyst #4 $/ft3 Gas Flow Calculations for SCR

Catalyst #5 $/ft3 123,200 dscfm @ 68o F

Filter Bags $/bag 17.5% Moisture

Tower Packing $/ft3 850 Deg F

Replacement Parts 252,207 acfm @ 850o F

Replacement Parts 0.4 NOx in lb/MMBtu

N/A

Other

Sales Tax 6.5 %

Interest Rate 7.00%

Standard interest rate specified by the US Office of Management and 

Budget

Operating Information

Annual Op. Hrs 8760 Hours Engineering Estimate

Utilization Rate 80% 2011 MDU data - Telephone Call 12/23/2010

Equipment Life 20 yrs Engineering Estimate

Design Capacity 572 MMBtu/hr 48 MW MDU data - Telephone Call 12/23/2010 Basis firing 100% coal

Standardized Flow Rate 149,961 scfm @ 32o F

Temperature 145 Deg F June 9, 2010 Stack Test

Stack O2 Content 4.0% June 9, 2010 Stack Test

Moisture Content 23.3% June 9, 2010 Stack Test

Actual Flow Rate 171,830 acfm acfm basis 145°F scrubber exhaust temperature

Standardized Flow Rate 160,934 scfm @ 68o F

Dry Std Flow Rate 123,200 dscfm @ 68o F June 9, 2010 Stack Test + 10% 

Max Emis

Pollutant Lb/Hr Uncontrolled Conc 

PM10 0.00 gr/dscf

Total Particulates 0.00 gr/dscf

Nitrous Oxides (NOx) 229 259 ppm Basis 0.4 lb NOx/MMBtu

Sulfur Dioxide (SO2) 286 233 ppm Baseline Emissions Basis 0.5 lb SO2/MMBtu

Sulfuric Acid Mist 0.000 ppm 0.50 lb SO2/MMBtu

Fluorides 0.0E+00 gr/dscf 0.0 ppb

Volatile Organic Compounds (VOC) 0.0 ppm

Carbon Monoxide (CO) 53.8 100.0 ppm 188 t/yr CO

Lead (Pb) 0.0E+00 gr/dscf 0 ppb

Enter this data for each emission unit

Enter data for this study (applies to all units)

Sargent & Lundy, SCR Cost Development Methodology, Aug 2010 and CoaLogix Gas Fired Plants SCR Management 

Considerations Nov 2009 McIlvaine Webinar
Appendix C1 Control Cost Worksheets 050611.xlsx

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-3 SO2 Control Spray Dry Absorber (SDA) with Baghouse FLM Cost Data

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0 Chemical Engineering

Design Capacity 572.0 MMBtu/hr Standardized Flow Rate 149,961 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 80% Temperature 145 Deg F 2008 NA

Expected Annual Hours of Operation 8,760 Hours Moisture Content 4.0% Jan-10 NA

Annual Interest Rate 7.0% Actual Flow Rate 171,830 acfm Inflation Adj NA

Expected Equipment Life 20 yrs Standardized Flow Rate 160,934 scfm @ 68o F

Dry Std Flow Rate 123,200 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs NA

 Purchased Equipment (A) NA

 Purchased Equipment Total (B) 15% of control device cost (A) NA

 Installation - Standard Costs 74% of purchased equip cost (B) NA

 Installation - Site Specific Costs NA

 Installation Total NA

 Total Direct Capital Cost, DC NA

 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) NA

Total Capital Investment (TCI) = DC + IC 66,336,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,078,971

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 8,976,085

Total Annual Cost (Annualized Capital Cost + Operating Cost) 10,055,057

Emission Control Cost Calculation

Max Emis Annual Design Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr Cont Eff Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 228.8 801.7 801.7 - NA

Sulfur Dioxide (SO2) 286.0 1,002.1 95% 0.08 lb/MMBtu 151.8 850.3 11,825

Sulfuric Acid Mist - - 0.00 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.00 - NA

Notes & Assumptions

1 Installed emission control equipment costs from Federal Land Managers summary of cost and perofrmance for proposed BART controls. Average Installed 

spraydryer absorber system and baghouse cost data adjusted to Lewis and Clark Station capacity

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 

3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1.5.1.8

4 Bag replacement at 10 min/bag EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min per bag.

5 Hydrated lime consumption 1.50 lb lime / lb SO2 removed at 1.3:1 stoichiometric ratio Lime:SO2
Appendix C1 Control Cost Worksheets 050611.xlsx

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-3 SO2 Control Spray Dry Absorber (SDA) with Baghouse FLM Cost Data

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) NA

Purchased Equipment Costs (A) 

Instrumentation 10% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (B) 15% NA

Installation

Foundations & supports 4% of purchased equip cost (B) NA

Handling & erection 50% of purchased equip cost (B) NA

Electrical 8% of purchased equip cost (B) NA

Piping 1% of purchased equip cost (B) NA

Insulation 7% of purchased equip cost (B) NA

Painting 4% of purchased equip cost (B) NA

Installation Subtotal Standard Expenses 74% NA

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total NA

Total Direct Capital Cost, DC NA

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) NA

Construction & field expenses 20% of purchased equip cost (B) NA

Contractor fees 10% of purchased equip cost (B) NA

Start-up 1% of purchased equip cost (B) NA

Performance test 1% of purchased equip cost (B) NA

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) NA

Total Indirect Capital Costs, IC 45% of purchased equip cost (B) NA

Total Capital Investment (TCI) (1) $1,382 per kW installed 66,336,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 65,979,568

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 33.50 $/Hr, 2.0 hr/8 hr shift, 8760 hr/yr 73,365

Supervisor 15% 15% of Operator Costs 11,005

Maintenance

Maintenance Labor 33.50 $/Hr, 1.0 hr/8 hr shift, 8760 hr/yr 36,683

Maintenance Materials 100% of maintenance labor costs 36,683

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 373 kW-hr, 8760 hr/yr, 80% utilization 149,027

NA NA - 

Water 1.16 $/mgal, 331 gpm, 8760 hr/yr, 80% utilization 161,346

NA NA - 

Comp Air (3) 0.37 $/mscf, 2 scfm/kacfm, 8760 hr/yr, 80% utilization 53,052

NA NA - 

NA NA - 

SW Disposal (CaSO4) 32.62 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization 100,999

NA NA - 

NA NA - 

NA NA - 

Hydrated Lime 290.00 $/ton, 364 lb/hr, 8760 hr/yr, 80% utilization 369,882

NA NA - 

NA NA - 

NA NA - 

Filter Bags 33.71 $/bag, 3,202 bags, 8760 hr/yr, 80% utilization 86,930

Total Annual Direct Operating Costs 1,078,971

Indirect Operating Costs

Overhead 60% of total labor and material costs 94,641

Administration (2% total capital costs) 2% of total capital costs (TCI) 1,326,720

Property tax (1% total capital costs) 1% of total capital costs (TCI) 663,360

Insurance (1% total capital costs) 1% of total capital costs (TCI) 663,360

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 6,228,004

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 8,976,085

Total Annual Cost (Annualized Capital Cost + Operating Cost) 10,055,057

See Summary page for notes and assumptions
Appendix C1 Control Cost Worksheets 050611.xlsx

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-3 SO2 Control Spray Dry Absorber (SDA) with Baghouse FLM Cost Data

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 5 years

CRF 0.0000

Rep part cost per unit 214 $/ft3

Amount Required 0 ft3

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment: Filter bags & cages

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit NA $/bag

Amount Required 3202

Total Rep Parts Cost 326,397 Cost adjusted for freight & sales tax

Installation Labor (4) 30,035 10 min per bag, Labor + Overhead (68% = $29.65/hr) EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4

Total Installed Cost 356,432 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag.

Annualized Cost 86,930

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW

Blower, Baghouse (2) 171,830 12 373.2 EPA Cont Cost Manual 6th ed Section 6 Chapter 1 Eq 1.14

Baghouse Shaker 0.0 Gross fabric area ft2 0

Other 

Other 

Other 

Other 

Other 

Total 373.2

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Gross BH Filter Area 42,958 ft2 - 4:1 air:cloth ratio assumed to determine baghouse area

Cages 10 ft long 5 in dia 13.42 area/cage ft2 3202 Cages 11.036 $/cage

Bags 1.69 $/ft2 of fabric 22.68 $/bag

Total 33.711

Lime Use Rate (5) 1.5 lb lime/lb SO2 removed 364 lb/hr Lime

 242.7 lb/hr SO2 Reduction

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.50 $/Hr 2.0 hr/8 hr shift 2,190 73,365 $/Hr, 2.0 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA 11,005 15% of Operator Costs

Maintenance

Maint Labor 33.50 $/Hr 1.0 hr/8 hr shift 1,095 36,683 $/Hr, 1.0 hr/8 hr shift, 8760 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 36,683 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 373.2 kW-hr 2,615,495 149,027 $/kwh, 373 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 331.0 gpm 139,179 161,346 $/mgal, 331 gpm, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air (3) 0.37 $/mscf 2 scfm/kacfm 144,502 53,052 $/mscf, 2 scfm/kacfm, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatemen 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal (CaSO4) 32.62 $/ton 0.4 ton/hr 3,096 100,999 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 326 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Transport 0.65 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Recycle 0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Hydrated Lime 290.00 $/ton 364 lb/hr 1,275 369,882 $/ton, 364 lb/hr, 8760 hr/yr, 80% utilization

Caustic 334.33 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

SCR Catalyst 214.29 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

Filter Bags 33.71 $/bag 3202 bags NA 86,930 $/bag, 3,202 bags, 8760 hr/yr, 80% utilization

*annual use rate is in same units of measurement as the unit cost factor
Appendix C1 Control Cost Worksheets 050611.xlsx

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-4 SO2 Control Dry Sorbent Injection (DSI) with Baghouse FLM Cost Data

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0 Chemical Engineering

Design Capacity 572.0 MMBtu/hr Standardized Flow Rate 149,961 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 80% Temperature 145 Deg F 2004 444.2

Expected Annual Hours of Operation 8,760 Hours Moisture Content 4.0% Aug-10 521.9

Annual Interest Rate 7.0% Actual Flow Rate 171,830 acfm Inflation Adj 1.17

Expected Equipment Life 20 yrs Standardized Flow Rate 160,934 scfm @ 68o F

Dry Std Flow Rate 123,200 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) (Baghouse) 3,618,757

 Purchased Equipment Total (B) 15% of control device cost (A) 4,161,571

 Installation - Standard Costs 74% of purchased equip cost (B) 3,079,562

 Installation - Site Specific Costs NA

 Installation Total 3,079,562

 Total Direct Capital Cost, DC 7,241,133

 Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 1,872,707

Total Capital Investment (TCI) = DC + IC 15,746,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 663,587

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,177,147

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,840,734

Emission Control Cost Calculation

Max Emis Annual Design Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr Cont Eff Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 228.8 801.7 801.7 - NA

Sulfur Dioxide (SO2) 286.0 1,002.1 70% 0.45 lb/MMBtu 901.9 100.2 28,347

Sulfuric Acid Mist - - 0.00 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.00 - NA

Notes & Assumptions

1 Installed emission control equipment costs from Federal Land Manager Summary of Cost and perofrmance for proposed BART controls. Installed 

sorbent injection system cost data Dominion in Kincaid, IL adjusted to Lewis and Clark Station capacity. Installed baghouse cost per 2004 Sargent and Lundy cost estimate

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1 

3 Compressed air for baghouse assumed to be 2 scfm / 1000 acfm EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 6 Chapter 1.5.1.8

4 Bag replacement at 10 min/bag EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4 lists replacement times from 5 - 20 min per bag.

5 Hydrated lime consumption 1.50 lb lime / lb SO2 removed at 1.3:1 stoichiometric ratio Lime:SO2

6

7

8
Appendix C1 Control Cost Worksheets 050611.xlsx

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-4 SO2 Control Dry Sorbent Injection (DSI) with Baghouse FLM Cost Data

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1) 3,618,757

Purchased Equipment Costs (A) 

Instrumentation 10% of control device cost (A) 361,876

Freight 5% of control device cost (A) 180,938

Purchased Equipment Total (B) 15% 4,161,571

Installation

Foundations & supports 4% of purchased equip cost (B) 166,463

Handling & erection 50% of purchased equip cost (B) 2,080,785

Electrical 8% of purchased equip cost (B) 332,926

Piping 1% of purchased equip cost (B) 41,616

Insulation 7% of purchased equip cost (B) 291,310

Painting 4% of purchased equip cost (B) 166,463

Installation Subtotal Standard Expenses 74% 3,079,562

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total 3,079,562

Total Direct Capital Cost, DC 7,241,133

Indirect Capital Costs

Engineering, supervision 10% of purchased equip cost (B) 416,157

Construction & field expenses 20% of purchased equip cost (B) 832,314

Contractor fees 10% of purchased equip cost (B) 416,157

Start-up 1% of purchased equip cost (B) 41,616

Performance test 1% of purchased equip cost (B) 41,616

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) 124,847

Total Indirect Capital Costs, IC 45% of purchased equip cost (B) 1,872,707

Baghouse Installed Cost (1) 9,113,840

Dry Sorbent Inj Intalled Cost (1) $123 per kW installed Dry Sorbent Injection 5,904,000

Total Capital Investment (TCI) + Retrofit Factor 15,746,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 15,389,568

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 33.50 $/Hr, 2.0 hr/8 hr shift, 8760 hr/yr 73,365

Supervisor 15% 15% of Operator Costs 11,005

Maintenance

Maintenance Labor 33.50 $/Hr, 1.0 hr/8 hr shift, 8760 hr/yr 36,683

Maintenance Materials 100% of maintenance labor costs 36,683

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 373 kW-hr, 8760 hr/yr, 80% utilization 149,027

NA NA - 

Water 1.16 $/mgal, 331 gpm, 8760 hr/yr, 80% utilization 161,346

NA NA - 

Comp Air (3) 0.37 $/mscf, 2 scfm/kacfm, 8760 hr/yr, 80% utilization 53,052

NA NA - 

NA NA - 

SW Disposal (CaSO4) 32.62 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization 11,903

NA NA - 

NA NA - 

NA NA - 

Hydrated Lime 290.00 $/ton, 43 lb/hr, 8760 hr/yr, 80% utilization 43,593

NA NA - 

NA NA - 

NA NA - 

Filter Bags 33.71 $/bag, 3,202 bags, 8760 hr/yr, 80% utilization 86,930

Total Annual Direct Operating Costs 663,587

Indirect Operating Costs

Overhead 60% of total labor and material costs 94,641

Administration (2% total capital costs) 2% of total capital costs (TCI) 314,920

Property tax (1% total capital costs) 1% of total capital costs (TCI) 157,460

Insurance (1% total capital costs) 1% of total capital costs (TCI) 157,460

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 1,452,666

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,177,147

Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,840,734

See Summary page for notes and assumptions
Appendix C1 Control Cost Worksheets 050611.xlsx

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-4 SO2 Control Dry Sorbent Injection (DSI) with Baghouse FLM Cost Data

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 5 years

CRF 0.0000

Rep part cost per unit 214 $/ft3

Amount Required 0 ft3

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment: Filter bags & cages

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit NA $/bag

Amount Required 3202

Total Rep Parts Cost 326,397 Cost adjusted for freight & sales tax

Installation Labor (4) 30,035 10 min per bag, Labor + Overhead (68% = $29.65/hr) EPA Cont Cost Manual 6th ed Section 6 Chapter 1.5.1.4

Total Installed Cost 356,432 Zero out if no replacement parts needed lists replacement times from 5 - 20 min per bag.

Annualized Cost 86,930

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW

Blower, Baghouse (2) 171,830 12 373.2

Baghouse Shaker 0.0 Gross fabric area ft2 0 EPA Cont Cost Manual 6th ed Section 6 Chapter 1 Eq 1.14

Other 

Other 

Other 

Other 

Other 

Total 373.2

Baghouse Filter Cost See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Gross BH Filter Area 42,958 ft2 - 4:1 air:cloth ratio assumed to determine baghouse area

Cages 10 ft long 5 in dia 13.42 area/cage ft2 3202 Cages 11.036 $/cage

Bags 1.69 $/ft2 of fabric 22.68 $/bag

Total 33.711

Lime Use Rate (5) 1.5 lb lime/lb SO2 removed 43 lb/hr Lime

 28.6 lb/hr SO2 Reduction

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.50 $/Hr 2.0 hr/8 hr shift 2,190 73,365 $/Hr, 2.0 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA 11,005 15% of Operator Costs

Maintenance

Maint Labor 33.50 $/Hr 1.0 hr/8 hr shift 1,095 36,683 $/Hr, 1.0 hr/8 hr shift, 8760 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 36,683 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 373.2 kW-hr 2,615,495 149,027 $/kwh, 373 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 331.0 gpm 139,179 161,346 $/mgal, 331 gpm, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air (3) 0.37 $/mscf 2 scfm/kacfm 144,502 53,052 $/mscf, 2 scfm/kacfm, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatemen 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal (CaSO4) 32.62 $/ton 0.1 ton/hr 365 11,903 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 326 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Transport 0.65 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Recycle 0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Hydrated Lime 290.00 $/ton 43 lb/hr 150 43,593 $/ton, 43 lb/hr, 8760 hr/yr, 80% utilization

Caustic 334.33 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

SCR Catalyst 214.29 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

Filter Bags 33.71 $/bag 3202 bags NA 86,930 $/bag, 3,202 bags, 8760 hr/yr, 80% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

SO2-Existing Scrubber 6/3/2011 Page 1 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-5 SO2 Control Increase Existing Wet Scrubber Efficiency

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0

Design Capacity 572 MMBtu/hr Standardized Flow Rate 149,961 scfm @ 32o F

Expected Utilization Rate 80% Temperature 145 Deg F

Expected Annual Hours of Operation 8,760 Hours Moisture Content 23.3%

Annual Interest Rate 7.0% Actual Flow Rate 171,830 0

Expected Equipment Life 20 yrs Standardized Flow Rate 160,934 acfm

Dry Std Flow Rate 123,200 scfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs

 Direct Capital Costs

 Purchased Equipment (A) NA

 Purchased Equipment Total (B) 22% of control device cost (A) NA

NA

 Installation - Standard Costs 85% of purchased equip cost (B)

 Installation - Site Specific Costs NA

 Installation Total NA

 Total Direct Capital Cost, DC NA

 Total Indirect Capital Costs, IC 35% of purchased equip cost (B) NA

Total Capital Investment (TCI) = DC + IC 270,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 77,810

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 60,827

Total Annual Cost (Annualized Capital Cost + Operating Cost) 138,637

Emission Control Cost Calculation

Max Emis Annual Design Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr Cont Eff Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 228.8 801.7 801.7 - NA

Sulfur Dioxide (SO2) 286.0 1,002.1 70% 0.45 lb/MMBtu 901.9 100.2 1,383

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - - - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.00 - NA

Notes & Assumptions

1 Sargent and Lundy installed cost estimate for lime silo upgrade needed to increase existing wet scrubber SO2 control efficiency

2 Calculations per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 5.2 Chapter 1 

3 Hydrated lime consumption 1.27 lb lime / lb SO2 removed at 1.1:1 stoichiometric ratio Lime:SO2
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

SO2-Existing Scrubber 6/3/2011 Page 2 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-5 SO2 Control Increase Existing Wet Scrubber Efficiency

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) NA

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC 

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 6.5% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (B) 22%

Installation NA

Foundations & supports 12% of purchased equip cost (B) NA

Handling & erection 40% of purchased equip cost (B) NA

Electrical 1% of purchased equip cost (B) NA

Piping 30% of purchased equip cost (B) NA

Insulation 1% of purchased equip cost (B) NA

Painting 1% of purchased equip cost (B) NA

Installation Subtotal Standard Expenses 85%

NA

Site Preparation, as required Site Specific NA

Buildings, as required Site Specific NA

Site Specific - Other Site Specific NA

Total Site Specific Costs NA

Installation Total NA

Total Direct Capital Cost, DC 

Indirect Capital Costs NA

Engineering, supervision 10% of purchased equip cost (B) NA

Construction & field expenses 10% of purchased equip cost (B) NA

Contractor fees 10% of purchased equip cost (B) NA

Start-up 1% of purchased equip cost (B) NA

Performance test 1% of purchased equip cost (B) NA

Model Studies NA of purchased equip cost (B) NA

Contingencies 3% of purchased equip cost (B) NA

Total Indirect Capital Costs, IC 35% of purchased equip cost (B) NA

Total Capital Investment (TCI) = DC + IC (1) 270,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 270,000

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 33.50 $/Hr, 0.1 hr/8 hr shift, 8760 hr/yr 3,668

Supervisor 15% 15% of Operator Costs 550

Maintenance

Maintenance Labor 33.50 $/Hr, 0.5 hr/8 hr shift, 8760 hr/yr 18,341

Maintenance Materials 100% of maintenance labor costs 18,341

Utilities, Supplies, Replacements & Waste Management

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Hydrated Lime 290.00 $/ton, 36 lb/hr, 8760 hr/yr, 80% utilization 36,909

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 77,810

Indirect Operating Costs

Overhead 60% of total labor and material costs 24,541

Administration (2% total capital costs) 2% of total capital costs (TCI) 5,400

Property tax (1% total capital costs) 1% of total capital costs (TCI) 2,700

Insurance (1% total capital costs) 1% of total capital costs (TCI) 2,700

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 25,486

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 60,827

Total Annual Cost (Annualized Capital Cost + Operating Cost) 138,637

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

SO2-Existing Scrubber 6/3/2011 Page 3 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-5 SO2 Control Increase Existing Wet Scrubber Efficiency

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst:

Equipment Life 5 years

CRF 0.0000

Rep part cost per unit 214 $/ft3

Amount Required 0 ft3

Packing Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment:

Equipment Life 3

CRF 0.3811

Rep part cost per unit 0 $ each

Amount Required 0 Number

Total Rep Parts Cost 0 Cost adjusted for freight & sales tax

Installation Labor 0 10 min per bag (13 hr total) Labor at $29.65/hr OAQPS list replacement times from 5 - 20 min per bag.

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Electrical Use

Flow acfm D P in H2O Efficiency Hp kW

Blower, Scrubber (2) 171,830 8.55 0.7 - 245.6 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.48

Flow Liquid SPGR D P ft H2O Efficiency Hp kW

Circ Pump 1,718 gpm 1 60 0.7 - 27.7 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

H2O WW Disch 0 gpm 1 60 0.7 - 0.0 EPA Cont Cost Manual 6th ed Section 5.2 Chapter 1 Eq 1.49

Other 

Other 

Other 

Total 0.0 Net power cost 0, no increase in electric use.

Reagent Use & Other Operating Costs

Overall Control Eff 70% SO2 Controlled by Lime 29 lb/hr SO2

Lime Use (3) 1.27 lb Lime/lb SO2 36 lb/hr Lime

Liquid/Gas ratio 10.0 * L/G = Gal/1,000 acf

Circulating Water Rate 1,718 gpm

Water Makeup Rate/WW Disch = NA of circulating water rate = 0 gpm No change in water use assumed

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.5 $/Hr 0.10 hr/8 hr shift 110 3,668 $/Hr, 0.1 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA 550 15% of Operator Costs

Maintenance

Maint Labor 33.50 $/Hr 0.5 hr/8 hr shift 548 18,341 $/Hr, 0.5 hr/8 hr shift, 8760 hr/yr

Maint Mtls 100 % of Maintenance Labor NA 18,341 100% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 0 scfm 0 0 $/mscf, 0 scfm, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air 0.37 $/mscf 0 Mscfm 0 0 $/mscf, 0 Mscfm, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatemen 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal 32.62 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 326 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Transport 0.65 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Recycle 0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Hydrated Lime 290.00 $/ton 36.3 lb/hr 127 36,909 $/ton, 36 lb/hr, 8760 hr/yr, 80% utilization

Caustic 334.33 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

SCR Catalyst 214.29 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

N/A 0.00 0 0 0 0 0, 0 , 8760 hr/yr, 80% utilization

*annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions
Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-6: Selective Catalytic Reduction (SCR) FLM $/KW Calculation

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0 Chemical Engineering

Design Capacity 572 MMBtu/hr Standardized Flow Rate 149,961 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 80% Temperature 850 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,760 17.5% Moisture Content 4.0% Oxygen Jul-10 550.7

Annual Interest Rate 7.0% Actual Flow Rate 252,207 acfm @ 850o F Inflation Adj 1.41

Expected Equipment Life 20 yrs Standardized Flow Rate 160,934 scfm @ 68o F

Dry Std Flow Rate 123,200 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu

 Direct Capital Costs EPRI Correlation 572 90% 0.40 NA

 Purchased Equipment (A) NA

 Purchased Equipment Total (B) 22% of control device cost (A) NA

 Installation - Standard Costs 15% of purchased equip cost (B) NA

 Installation - Site Specific Costs 0

 Installation Total NA

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC NA

Total Capital Investment (TCI) + Retrofit 38,976,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 1,153,201

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,831,176

Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,984,376

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 228.8 801.7 90% 0.04 lb/MMBtu 80.2 721.5 9,680

Sulfur Dioxide (SO2) 286.0 1,002.1 1002.1 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 Installed emission control equipment costs from Federal Land Manager Summary of Cost and perofrmance for proposed BART controls. Average installed 

selective catalytic reduction system cost data adjusted to Lewis and Clark Station capacity. Installed baghouse cost per 2004 Sargent and Lundy cost estimate

2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

3 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

4 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

5 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

6 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-6: Selective Catalytic Reduction (SCR) FLM $/KW Calculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC NA

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 7.0% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 22% NA

Indirect Installation

General Facilities 5% of purchased equip cost (A) NA

Engineering & Home Office 10% of purchased equip cost (A) NA

Process Contingency 5% of purchased equip cost (A) NA

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) NA

Project Contingency ( C) 15% of (A + B) NA

Total Plant Cost D A + B + C NA

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) NA

Inventory Capital Reagent Vol * $/gal 18,823

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I NA

Retrofit Factor 30% of TCI NA

Installed Cost 

Total Capital Investment (TCI) (1) $812 per kW installed 38,976,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 33.50 $/Hr, 0.2 hr/8 hr shift, 8760 hr/yr 7,337

Supervisor 15% 15% of Operator Costs 1,100

Maintenance

Maintenance Total (6) 1.50 1.5% of Total Capital Investment 584,640

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 232 kW-hr, 8760 hr/yr, 80% utilization 92,803

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Aqua Ammonia 0.70 $/lb, 80 lb/hr, 8760 hr/yr, 80% utilization 392,593

NA NA - 

SCR Catalyst 214.29 $/ft3, 0 , 8760 hr/yr, 80% utilization 74,728

NA NA - 

Total Annual Direct Operating Costs 1,153,201

Indirect Operating Costs

Overhead 60% of total labor and material costs 593,077

Administration (2% total capital costs) 2% of total capital costs (TCI) 779,520

Property tax (1% total capital costs) 1% of total capital costs (TCI) 389,760

Insurance (1% total capital costs) 1% of total capital costs (TCI) 389,760

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,679,059

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,831,176

Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,984,376

See Summary page for notes and assumptions
Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-6: Selective Catalytic Reduction (SCR) FLM $/KW Calculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 yrs

CRF 0.0944

Replacement Catalyst (4)

Equipment Life 24,000 hours

FCW 0.3111

Rep part cost per unit 214 $/ft3 # of Layers 3

Replacement Factor 3 Layers replaced per year = 1

Amount Required 1,121 ft3

Catalyst Cost 240,242

Y catalyst life factor 3 Years

Annualized Cost 74,728

SCR Catalyst Volume (3)

Duty 572 MMBtu/hr Catalyst Area 263 ft2 167 f(h SCR)

Q flue gas 252,207 acfm Rx Area 302 193 f(h NH3)

NOx Cont Eff 90% (as faction) Rx Height 17.4 ft 0 f(h New) new= -728, Retrofit = 0

NOx in 0.40 lb/MMBtu n layer 3 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 5.3 ft 127 f(h Bypass)

Fuel Sulfur 0.5 wt % (as %) n total 4 layers 807,212 f(vol catalyst)

Temperature 850 Deg F h SCR 58 ft f(h SCR)

Catalyst Volume 3,363 ft3 New/Retrofit N N or R 

Electrical Use (5)

Duty 572 MMBtu/hr kW

NOx Cont Eff 90% (as faction) Power 232.4

NOx in 0.40 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 232.4

Reagent Use & Other Operating Costs (2) Ammonia Use

NOx in 0.40 lb/MMBtu 80 lb/hr Neat 1.05 Stoichiometric Ratio

Efficiency 90% 19% solution 56.0 lb/ft3 Density

Duty 572 MMBtu/hr 421 lb/hr 56.3 gal/hr

Volume 14 day inventory 18,906 gal $18,823 Inventory Cost

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.5 $/Hr 0.2 hr/8 hr shift 219 7,337 $/Hr, 0.2 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA 1,100 15% of Operator Costs

Maintenance

Maintenance Total (6) 1.5 % of Total Capital Investment 584,640 1.5% of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 232.4 kW-hr 1,628,748 92,803 $/kwh, 232 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 0.0 scfh 0 0 $/mscf, 0 scfh, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 0.0 gph 0 0 $/mgal, 0 gph, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air 0.37 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatement 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal 326.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 1 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

N/A 0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

N/A 0.00 0.00 0.0 ton/hr 0 0 0, 0 ton/hr, 8760 hr/yr, 80% utilization

Lime 0.00 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

Aqua Ammonia 0.70 $/lb 80 lb/hr 560,847 392,593 $/lb, 80 lb/hr, 8760 hr/yr, 80% utilization

Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

SCR Catalyst 214.29 $/ft3 74,728 $/ft3, 0 , 8760 hr/yr, 80% utilization

N/A 0 0 0 0 0 0 0, 0 0, 8760 hr/yr, 80% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

NOx LNB&SNCR S&L 6/3/2011 Page 1 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-7 - Level 3 Low NOx Burners with SOFA and Selective Non-Catalytic Reduction 

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0 Chemical Engineering

Design Capacity 572.0 Standardized Flow Rate 149,961 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 80% Temperature 145 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,760 Hours Moisture Content 4.0% Jul-10 550.7

Annual Interest Rate 7.0% Actual Flow Rate 171,830 acfm Inflation Adj 1.41

Expected Equipment Life 20 yrs Standardized Flow Rate 160,934 scfm @ 68o F

Dry Std Flow Rate 123,200 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year

 Direct Capital Costs EPRI Correlation, 1998 $'s 572 25% 0.40 1998 NA

 Purchased Equipment (A) 2010 NA

 Purchased Equipment Total (B) 0% of control device cost (A) NA

 Installation - Standard Costs 15% of purchased equip cost (B) 0

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC 4,531,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 444,249

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 649,713

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,093,962

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 228.8 801.7 50% 0.20 lb NOx/MMbtu 400.9 400.9 2,729

Sulfur Dioxide (SO2) 286.0 1,002.1 1002.1 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 "Conceptual Design Study for NOx Reduction Tehcnologies" March, 2011 A site specifice enginieering and cost evaluation prepared by Sargent and Lundy, LLC 

2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22

3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25

4 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29

5 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23

6 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

NOx LNB&SNCR S&L 6/3/2011 Page 2 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-7 - Level 3 Low NOx Burners with SOFA and Selective Non-Catalytic Reduction 

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) 

Purchased Equipment Costs (A) NA

Instrumentation 10% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) NA

Indirect Installation

General Facilities 5% of purchased equip cost (A) NA

Engineering & Home Office 10% of purchased equip cost (A) NA

Process Contingency 5% of purchased equip cost (A) NA

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) NA

Project Contingency ( C) 15% of (A + B) 0

SNCR Equipment Subtotal NA

Total Plant Cost D A + B + C 0

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 0

Inventory Capital Reagent Vol * $/gal 0

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) (1) 4,531,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 4,531,000

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total (5) 1.50 1.5% of Total Capital Investment 67,965

NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh, 9 kW-hr, 8760 hr/yr, 80% utilization 3,685

Natural Gas 6.85 $/mscf, 1 scfh, 8760 hr/yr, 80% utilization 54,082

Water 1.16 $/mgal, 68 gph, 8760 hr/yr, 80% utilization 552

NA

NA

NA

NA NA - 

NA NA - 

NA NA - 

NA NA - 

SW Disposal 32.62 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization 1,011

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Urea 50% Solution 637.60 $/ton , 0 ton/hr, 8760 hr/yr, 80% utilization 316,954

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 444,249

Indirect Operating Costs

Overhead 60% of total labor and material costs 40,779

Administration (2% total capital costs) 2% of total capital costs (TCI) 90,620

Property tax (1% total capital costs) 1% of total capital costs (TCI) 45,310

Insurance (1% total capital costs) 1% of total capital costs (TCI) 45,310

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 427,694

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 649,713

Total Annual Cost (Annualized Capital Cost + Operating Cost) 1,093,962

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

NOx LNB&SNCR S&L 6/3/2011 Page 3 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-7 - Level 3 Low NOx Burners with SOFA and Selective Non-Catalytic Reduction 

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst <- Enter Equipment Name to Get Cost

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 214 $/ft3

Amount Required 12 ft3

Packing Cost 2,700 Cost adjusted for freight

Installation Labor 405 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 650 $/ft3

Amount Required 0 Cages

Total Rep Parts Cost 0 Cost adjusted for freight See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr)

Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag.

Annualized Cost 0

Electrical Use (5)

NOx in 0.40 lb/MMBtu kW

NSR 0.82

Power 9.2

Total 9.2

Reagent Use & Other Operating Costs Urea Use (2)

NOx in 0.40 lb/MMBtu 71 lb/hr Neat 0.04

Efficiency 25% 50% solution 71.0 lb/ft3 Density 50% Solution

Duty 572 MMBtu/hr 142 lb/hr 14.9 gal/hr

Volume 14 day inventory 5,023 gal $15,196 Inventory Cost

Water Use (3) 68 gal/hr Inject at 10% solution

Fuel Use (4) 1.1 MMBtu/hr 1.1 mscfh natural gas

Ash Generation 8.8 lb/hr

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.50 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA - 15% of Operator Costs

Maintenance

Maintenance Total (5) 1.5 % of Total Capital Investment 67,965 1.5% of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 9.2 kW-hr 64,669 3,685 $/kwh, 9 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 1.1 scfh 7,895 54,082 $/mscf, 1 scfh, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 68.0 gph 477 552 $/mgal, 68 gph, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air 0.37 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatement 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal 32.62 $/ton 0.004 ton/hr 31 1,011 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 326.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Transport 0.65 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Lime 0.00 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

Urea 50% Solution 637.60 $/ton 0.0709 ton/hr 497 316,954 $/ton , 0 ton/hr, 8760 hr/yr, 80% utilization

Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

SCR Catalyst 214.285714 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

CO Catalyst 650 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

NOx SNCR S&L 6/3/2011 Page 1 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-8 - Selective Non-Catalytic Reduction 

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0 Chemical Engineering

Design Capacity 572.0 Standardized Flow Rate 149,961 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 80% Temperature 145 Deg F 1998/1999 NA

Expected Annual Hours of Operation 8,760 Hours Moisture Content 4.0% Jul-10 NA

Annual Interest Rate 7.0% Actual Flow Rate 171,830 acfm Inflation Adj NA

Expected Equipment Life 20 yrs Standardized Flow Rate 160,934 scfm @ 68o F

Dry Std Flow Rate 123,200 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year

 Direct Capital Costs EPRI Correlation, 1998 $'s 572 25% 0.40 1998 NA

 Purchased Equipment (A) 2010 NA

 Purchased Equipment Total (B) 0% of control device cost (A) NA

 Installation - Standard Costs 15% of purchased equip cost (B) 0

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC 2,433,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 412,779

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 348,875

Total Annual Cost (Annualized Capital Cost + Operating Cost) 761,654

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 228.8 801.7 38% 0.25 lb NOx/MMbtu 501.1 300.6 2,533

Sulfur Dioxide (SO2) 286.0 1,002.1 1002.1 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 "Conceptual Design Study for NOx Reduction Tehcnologies" March, 2011 A site specifice enginieering and cost evaluation prepared by Sargent and Lundy, LLC 

2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22

3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25

4 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29

5 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23

6 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

NOx SNCR S&L 6/3/2011 Page 2 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-8 - Selective Non-Catalytic Reduction 

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) 

Purchased Equipment Costs (A) NA

Instrumentation 10% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) NA

Indirect Installation

General Facilities 5% of purchased equip cost (A) NA

Engineering & Home Office 10% of purchased equip cost (A) NA

Process Contingency 5% of purchased equip cost (A) NA

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) NA

Project Contingency ( C) 15% of (A + B) 0

SNCR Equipment Subtotal NA

Total Plant Cost D A + B + C 0

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 0

Inventory Capital Reagent Vol * $/gal 0

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) (1) 2,433,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 2,433,000

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total (6 1.50 1.5% of Total Capital Investment 36,495

NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh, 9 kW-hr, 8760 hr/yr, 80% utilization 3,685

Natural Gas 6.85 $/mscf, 1 scfh, 8760 hr/yr, 80% utilization 54,082

Water 1.16 $/mgal, 68 gph, 8760 hr/yr, 80% utilization 552

NA

NA

NA

NA NA - 

NA NA - 

NA NA - 

NA NA - 

SW Disposal 32.62 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization 1,011

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Urea 50% Solution 637.60 $/ton , 0 ton/hr, 8760 hr/yr, 80% utilization 316,954

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 412,779

Indirect Operating Costs

Overhead 60% of total labor and material costs 21,897

Administration (2% total capital costs) 2% of total capital costs (TCI) 48,660

Property tax (1% total capital costs) 1% of total capital costs (TCI) 24,330

Insurance (1% total capital costs) 1% of total capital costs (TCI) 24,330

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 229,658

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 348,875

Total Annual Cost (Annualized Capital Cost + Operating Cost) 761,654

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

NOx SNCR S&L 6/3/2011 Page 3 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-8 - Selective Non-Catalytic Reduction 

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst <- Enter Equipment Name to Get Cost

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 214 $/ft3

Amount Required 12 ft3

Packing Cost 2,700 Cost adjusted for freight

Installation Labor 405 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 650 $/ft3

Amount Required 0 Cages

Total Rep Parts Cost 0 Cost adjusted for freight See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr)

Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag.

Annualized Cost 0

Electrical Use (5)

NOx in 0.40 lb/MMBtu kW

NSR 0.82

Power 9.2

Total 9.2

Reagent Use & Other Operating Costs Urea Use (2)

NOx in 0.40 lb/MMBtu 71 lb/hr Neat 0.04

Efficiency 25% 50% solution 71.0 lb/ft3 Density 50% Solution

Duty 572 MMBtu/hr 142 lb/hr 14.9 gal/hr

Volume 14 day inventory 5,023 gal $15,196 Inventory Cost

Water Use (3) 68 gal/hr Inject at 10% solution

Fuel Use (4) 1.1 MMBtu/hr 1.1 mscfh natural gas

Ash Generation 8.8 lb/hr

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.50 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA - 15% of Operator Costs

Maintenance

Maintenance Total (6 1.5 % of Total Capital Investment 36,495 1.5% of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 9.2 kW-hr 64,669 3,685 $/kwh, 9 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 1.1 scfh 7,895 54,082 $/mscf, 1 scfh, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 68.0 gph 477 552 $/mgal, 68 gph, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air 0.37 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatement 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal 32.62 $/ton 0.004 ton/hr 31 1,011 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 326.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Transport 0.65 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Lime 0.00 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

Urea 50% Solution 637.60 $/ton 0.0709 ton/hr 497 316,954 $/ton , 0 ton/hr, 8760 hr/yr, 80% utilization

Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

SCR Catalyst 214.285714 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

CO Catalyst 650 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C1 Control Cost Worksheets 050611.xlsx

NOx LNB S&L 6/3/2011 Page 1 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-9 - Level 3 Low NOx Burners with Separated Overfire Air (SOFA)

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0 Chemical Engineering

Design Capacity 572.0 Standardized Flow Rate 149,961 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 80% Temperature 145 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,760 Hours Moisture Content 4.0% Jul-10 550.7

Annual Interest Rate 7.0% Actual Flow Rate 171,830 acfm Inflation Adj 1.41

Expected Equipment Life 20 yrs Standardized Flow Rate 160,934 scfm @ 68o F

Dry Std Flow Rate 123,200 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year

 Direct Capital Costs EPRI Correlation, 1998 $'s 572 25% 0.40 1998 NA

 Purchased Equipment (A) 2010 NA

 Purchased Equipment Total (B) 0% of control device cost (A) NA

 Installation - Standard Costs 15% of purchased equip cost (B) 0

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC 2,195,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 43,471

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 321,075

Total Annual Cost (Annualized Capital Cost + Operating Cost) 364,546

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 228.8 801.7 38% 0.25 lb NOx/MMbtu 501.1 300.6 1,213

Sulfur Dioxide (SO2) 286.0 1,002.1 1002.1 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 "Conceptual Design Study for NOx Reduction Tehcnologies" March, 2011 A site specifice enginieering and cost evaluation prepared by Sargent and Lundy, LLC 
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NOx LNB S&L 6/3/2011 Page 2 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-9 - Level 3 Low NOx Burners with Separated Overfire Air (SOFA)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) 

Purchased Equipment Costs (A) NA

Instrumentation 10% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) NA

Indirect Installation

General Facilities 5% of purchased equip cost (A) NA

Engineering & Home Office 10% of purchased equip cost (A) NA

Process Contingency 5% of purchased equip cost (A) NA

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) NA

Project Contingency ( C) 15% of (A + B) 0

SNCR Equipment Subtotal NA

Total Plant Cost D A + B + C 0

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 0

Inventory Capital Reagent Vol * $/gal 0

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) 1 2,195,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 2,195,000

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 33.50 $/Hr, 0.3 hr/8 hr shift, 8760 hr/yr 9,171

Supervisor 15% 15% of Operator Costs 1,376

Maintenance

Maintenance Total 1.50 1.5% of Total Capital Investment 32,925

NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

NA NA - 

NA NA - 

NA NA - 

NA

NA

NA

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 43,471

Indirect Operating Costs

Overhead 60% of total labor and material costs 26,083

Administration (2% total capital costs) 2% of total capital costs (TCI) 43,900

Property tax (1% total capital costs) 1% of total capital costs (TCI) 21,950

Insurance (1% total capital costs) 1% of total capital costs (TCI) 21,950

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 207,192

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 321,075

Total Annual Cost (Annualized Capital Cost + Operating Cost) 364,546

See Summary page for notes and assumptions
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NOx LNB S&L 6/3/2011 Page 3 of 3

Appendix C.1 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities

Table C.1-9 - Level 3 Low NOx Burners with Separated Overfire Air (SOFA)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst <- Enter Equipment Name to Get Cost

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 214 $/ft3

Amount Required 12 ft3

Packing Cost 2,700 Cost adjusted for freight

Installation Labor 405 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 650 $/ft3

Amount Required 0 Cages

Total Rep Parts Cost 0 Cost adjusted for freight See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr)

Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag.

Annualized Cost 0

Electrical Use

NOx in 0.40 lb/MMBtu kW

NSR 0.82

Power 9.2

Total 9.2

Reagent Use & Other Operating Costs Urea Use

NOx in 0.40 lb/MMBtu NA lb/hr Neat NA

Efficiency NA 50% solution 71.0 lb/ft3 Density 50% Solution

Duty 572 MMBtu/hr NA lb/hr NA gal/hr

Volume 14 day inventory NA gal NA Inventory Cost

Water Use NA gal/hr Inject at 10% solution

Fuel Use NA MMBtu/hr NA mscfh natural gas

Ash Generation NA lb/hr

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.50 $/Hr 0.3 hr/8 hr shift 274 9,171 $/Hr, 0.3 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA 1,376 15% of Operator Costs

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 32,925 1.5% of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 0.0 scfh 0 0 $/mscf, 0 scfh, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 0.0 gph 0 0 $/mgal, 0 gph, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air 0.37 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatement 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal 32.62 $/ton 0.000 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 326.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Transport 0.65 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

1 Lime 0.00 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

6 Urea 50% Solution 637.60 $/ton 0.0000 ton/hr 0 0 $/ton , 0 ton/hr, 8760 hr/yr, 80% utilization

5 Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

1 SCR Catalyst 214.285714 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

2 CO Catalyst 650 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions
Appendix C.2

Low Load Operation NOx Control Cost Worksheets
6/3/2011

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Summary Table Page 1 of 1

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-1 : Control Cost Summary 

NOx Control Cost Summary

Control Technology

Control lb 

NOx/MMBtu

Controlled 

Emissions T/y

Emission 

Reduction T/yr

Installed Capital 

Cost $

Annualized 

Operating Cost $/yr

Pollution Control 

Cost $/ton

Incremental 

Control Cost $/ton

Air Toxic's & 

AQRV's?

Energy 

Impacts?

Non-Air Env 

Impacts?

Selective Catalytic Reduction 0.04 35.5 319.8 $38,976,000 $6,692,645 $20,927 $31,263 Ammonia Slip Medium

Ammonia in 

Wastewater 

Discharge

SNCR + Low NOx Burners 

with SOFA 0.23 220.9 134.5 $4,531,000 $897,981 $6,679 $18,515

Ammonia 

Slip, Higher 

CO Emissions

Low

Ammonia in 

Wastewater 

Discharge

Selective Non Catalytic 

Reduction 0.31 297.7 57.6 $2,433,000 $565,673 $9,817 NA Ammonia Slip Low

Ammonia in 

Wastewater 

Discharge

Low NOx Burners with SOFA 0.26 249.7 105.6 $2,195,000 $364,546 $3,451 NA Higher CO 

Emissions None None

Baseline 0.37 355.3
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C2 23MW NOx Control Cost Worksheets 050611.xlsx

Utility Chem$ Data 6/3/2011 Page 1 of 1

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-2 : Labor, Chemical and Utility Costs

Operating Unit: NA Study Year 2011

Reference

Item Unit Cost Units Cost Year Data Source Notes

Operating Labor 33.5 $/hr 2006 Heskett Unit II BART Report

Maintenance Labor 33.5 $/hr 2006 Heskett Unit II BART Report

Electricity 0.057 $/kwh 0.049 2006 Heskett Unit II BART Report http://www.eia.doe.gov/emeu/aer/txt/ptb0810.html

Natural Gas 6.85 $/mscf 2005

Average natural gas spot price July 04 - 

June 05, Henry La Hub., WTRG Economics, WWW.wtrg.com/daily/small/ngspot.gig 

Water 1.16 $/mgal 1.00 2006 Heskett Unit II BART Report cost adjusted for 3% inflation

Cooling Water 0.32 $/mgal 0.23 1999

EPA Air Pollution Control Cost Manual, 6th 

ed. Section 3.1 Ch 1

Ch 1 Carbon Absorbers, 1999 $0.15 - $0.30 Avg of 22.5 and 7 yrs and 

3% inflation

Compressed Air 0.37 $/mscf 0.25 1998

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 6 Chapter 1 

Example problem; Dried & Filtered, Ch 1.6 '98 cost adjusted for 3% 

inflation

Wastewater Disposal Neutralization 1.96 $/mgal 1.50 2002

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $1- $2/1000 gal. Cost adjusted for 3% inflation Sec 6 

Ch 3 lists $1.30 - $2.15/1,000 gal

Wastewater Disposal Bio-Treat 4.96 $/mgal 3.80 2002

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 5.2 Chapter 1

Ch 1lists $1.00 - $6.00 for municipal treatment, $3.80 is average. Cost 

adjusted for 3% inflation

Solid Waste Disposal 32.62 $/ton 25.00 2002

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $20 - $30/ton Used $25/ton. Cost adjusted for 3% 

inflation

Hazardous Waste Disposal 326.19 $/ton 250.00 2002

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 2 Chapter 2.5.5.5

Section 2 lists $200 - $300/ton Used $250/ton. Cost adjusted for 3% 

inflation

Waste Transport 0.65 $/ton-mi 0.50 2002

EPA Air Pollution Control Cost Manual 6th 

Ed 2002, Section 6 Chapter 3 Example problem. Cost adjusted for 3% inflation

$/ton

Chemicals & Supplies

Lime 86.95 $/ton 75.00 2006 Heskett Unit II BART Report cost adjusted for 3% inflation

Caustic 334.33 $/ton 280 2005 Hawkins Chemical 50% solution (50 Deg Be) includes delivery

Ammonia 483.59 $/ton 405 2005 Heskett Unit II BART Report 50% solution of urea in water, includes delivery

Hydrated Lime 290.00 $/ton 290.00 2011 MDU 2009 Reagent Study 

Trona 158.45 Mscf 145 2008 Solvay Chemical cost adjusted for 3% inflation

Urea 50% Solution 637.60 $/ton 550.00 2006 Heskett Unit II BART Report

Aqua Ammonia 0.70 $/lb 0.70 2011 Barr Engineering Data $1,400/NH3 neat delivered at 19% aqua ammonia

Limestone 68.96 $/ton 65.00 2009 MDU 2009 Reagent Study 

NA

Catalyst & Replacement Parts 

SCR Catalyst 214 $/ft3

CO Catalyst 650 $/ft3 Vendor quote if needed

Catalyst #3 $/ft3

Catalyst #4 $/ft3 Gas Flow Calculations for SCR

Catalyst #5 $/ft3 59,033 dscfm @ 68o F

Filter Bags $/bag 17.5% Moisture

Tower Packing $/ft3 850 Deg F

Replacement Parts 120,849 acfm @ 850o F

Replacement Parts 0.4 NOx in lb/MMBtu

N/A

Other

Sales Tax 6.5 %

Interest Rate 7.00%

Standard interest rate specified by the US Office of Management and 

Budget

Operating Information

Annual Op. Hrs 8760 Hours Engineering Estimate

Utilization Rate 80% 2011 MDU data - Telephone Call 12/23/2010

Equipment Life 20 yrs 23 MW

Reduced Capacity Example - Telephone 

Call 2/9/2011 Engineering Estimate

Design Capacity 274 MMBtu/hr 48 MW MDU data - Telephone Call 12/23/2010 Basis firing 100% coal

Standardized Flow Rate 71,856 scfm @ 32o F

Temperature 145 Deg F June 9, 2010 Stack Test

Stack O2 Content 4.0% June 9, 2010 Stack Test

Moisture Content 23.3% June 9, 2010 Stack Test

Actual Flow Rate 82,335 acfm acfm basis 145°F scrubber exhaust temperature

Standardized Flow Rate 77,114 scfm @ 68o F

Dry Std Flow Rate 59,033 dscfm @ 68o F June 9, 2010 Stack Test + 10% 

Max Emis

Pollutant Lb/Hr Uncontrolled Conc 

PM10 0.00 gr/dscf

Total Particulates 0.00 gr/dscf

Nitrous Oxides (NOx) 101 240 ppm Basis 0.37 lb NOx/MMBtu

Sulfur Dioxide (SO2) 220 373 ppm Basis 0.5 %S Coal, 6,600 Btu/lb coal

Sulfuric Acid Mist 0.000 ppm 0.80 lb SO2/MMBtu

Fluorides 0.0E+00 gr/dscf 0.0 ppb

Volatile Organic Compounds (VOC) 0.0 ppm

Carbon Monoxide (CO) 53.8 208.7 ppm 188 t/yr CO

Lead (Pb) 0.0E+00 gr/dscf 0 ppb

Enter this data for each emission unit

Enter data for this study (applies to all units)

Sargent & Lundy, SCR Cost Development Methodology, Aug 2010 and CoaLogix Gas Fired Plants SCR Management 

Considerations Nov 2009 McIlvaine Webinar
Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-3: Selective Catalytic Reduction (SCR) FLM $/KW Calculation

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0 Chemical Engineering

Design Capacity 274 MMBtu/hr Standardized Flow Rate 71,856 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 80% Temperature 850 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,760 17.5% Moisture Content 4.0% Oxygen Jul-10 550.7

Annual Interest Rate 7.0% Actual Flow Rate 120,849 acfm @ 850o F Inflation Adj 1.41

Expected Equipment Life 20 yrs Standardized Flow Rate 77,114 scfm @ 68o F

Dry Std Flow Rate 59,033 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu

 Direct Capital Costs EPRI Correlation 274 90% 0.40 NA

 Purchased Equipment (A) NA

 Purchased Equipment Total (B) 22% of control device cost (A) NA

 Installation - Standard Costs 15% of purchased equip cost (B) NA

 Installation - Site Specific Costs 0

 Installation Total NA

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC NA

Total Capital Investment (TCI) + Retrofit 38,976,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 861,470

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,831,176

Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,692,645

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 101.4 355.3 90% 0.04 lb/MMBtu 35.5 319.8 20,927

Sulfur Dioxide (SO2) 220.1 771.2 771.2 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 Installed emission control equipment costs from Federal Land Manager Summary of Cost and perofrmance for proposed BART controls. Average installed 

selective catalytic reduction system cost data adjusted to Lewis and Clark Station capacity. Installed baghouse cost per 2004 Sargent and Lundy cost estimate

2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.32 - 2.35

3 SCR Catalyst Volume per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.18 - 2.24

4 SCR Catalyst Replacement per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.50 - 2.53

5 SCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.48

6 SCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 2 Eq 2.46
Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-3: Selective Catalytic Reduction (SCR) FLM $/KW Calculation

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) (1)

Purchased Equipment Costs (A) - Absorber + packing + auxiliary equipment, EC NA

Instrumentation 10% of control device cost (A) NA

MN Sales Taxes 7.0% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) 22% NA

Indirect Installation

General Facilities 5% of purchased equip cost (A) NA

Engineering & Home Office 10% of purchased equip cost (A) NA

Process Contingency 5% of purchased equip cost (A) NA

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) NA

Project Contingency ( C) 15% of (A + B) NA

Total Plant Cost D A + B + C NA

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) NA

Inventory Capital Reagent Vol * $/gal 9,019

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) = DC + IC D + E + F + G +H + I NA

Retrofit Factor 30% of TCI NA

Installed Cost 

Total Capital Investment (TCI) (1) $812 per kW installed 38,976,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost NA

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 33.50 $/Hr, 0.2 hr/8 hr shift, 8760 hr/yr 7,337

Supervisor 15% 15% of Operator Costs 1,100

Maintenance

Maintenance Total (6) 1.50 1.5% of Total Capital Investment 584,640

Maintenance Materials NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.06 $/kwh, 111 kW-hr, 8760 hr/yr, 80% utilization 44,468

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Aqua Ammonia 0.70 $/lb, 38 lb/hr, 8760 hr/yr, 80% utilization 188,117

NA NA - 

SCR Catalyst 214.29 $/ft3, 0 , 8760 hr/yr, 80% utilization 35,807

NA NA - 

Total Annual Direct Operating Costs 861,470

Indirect Operating Costs

Overhead 60% of total labor and material costs 593,077

Administration (2% total capital costs) 2% of total capital costs (TCI) 779,520

Property tax (1% total capital costs) 1% of total capital costs (TCI) 389,760

Insurance (1% total capital costs) 1% of total capital costs (TCI) 389,760

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 3,679,059

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 5,831,176

Total Annual Cost (Annualized Capital Cost + Operating Cost) 6,692,645

See Summary page for notes and assumptions
Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-3: Selective Catalytic Reduction (SCR) FLM $/KW Calculation

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 yrs

CRF 0.0944

Replacement Catalyst (4)

Equipment Life 24,000 hours

FCW 0.3111

Rep part cost per unit 214 $/ft3 # of Layers 3

Replacement Factor 3 Layers replaced per year = 1

Amount Required 537 ft3

Catalyst Cost 115,116

Y catalyst life factor 3 Years

Annualized Cost 35,807

SCR Catalyst Volume (3)

Duty 274 MMBtu/hr Catalyst Area 126 ft2 167 f(h SCR)

Q flue gas 120,849 acfm Rx Area 145 454 f(h NH3)

NOx Cont Eff 90% (as faction) Rx Height 12.0 ft 0 f(h New) new= -728, Retrofit = 0

NOx in 0.40 lb/MMBtu n layer 3 layers Y Bypass? Y or N

Ammonia Slip 2 ppm h layer 5.3 ft 127 f(h Bypass)

Fuel Sulfur 0.5 wt % (as %) n total 4 layers 386,789 f(vol catalyst)

Temperature 850 Deg F h SCR 58 ft f(h SCR)

Catalyst Volume 1,612 ft3 New/Retrofit N N or R 

Electrical Use (5)

Duty 274 MMBtu/hr kW

NOx Cont Eff 90% (as faction) Power 111.4

NOx in 0.40 lb/MMBtu

n catalyst layers 4 layers

Press drop catalyst 1 in H2O per layer

Press drop duct 3 in H2O 

Total 111.4

Reagent Use & Other Operating Costs (2) Ammonia Use

NOx in 0.40 lb/MMBtu 38 lb/hr Neat 1.05 Stoichiometric Ratio

Efficiency 90% 19% solution 56.0 lb/ft3 Density

Duty 274 MMBtu/hr 202 lb/hr 27.0 gal/hr

Volume 14 day inventory 9,059 gal $9,019 Inventory Cost

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.5 $/Hr 0.2 hr/8 hr shift 219 7,337 $/Hr, 0.2 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA 1,100 15% of Operator Costs

Maintenance

Maintenance Total (6) 1.5 % of Total Capital Investment 584,640 1.5% of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 111.4 kW-hr 780,442 44,468 $/kwh, 111 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 0.0 scfh 0 0 $/mscf, 0 scfh, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 0.0 gph 0 0 $/mgal, 0 gph, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air 0.37 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatement 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal 326.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 1 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

N/A 0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

N/A 0.00 0.00 0.0 ton/hr 0 0 0, 0 ton/hr, 8760 hr/yr, 80% utilization

Lime 86.95 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

Aqua Ammonia 0.70 $/lb 38 lb/hr 268,739 188,117 $/lb, 38 lb/hr, 8760 hr/yr, 80% utilization

Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

SCR Catalyst 214.29 $/ft3 35,807 $/ft3, 0 , 8760 hr/yr, 80% utilization

N/A 0 0 0 0 0 0 0, 0 0, 8760 hr/yr, 80% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C2 23MW NOx Control Cost Worksheets 050611.xlsx

NOx LNB&SNCR S&L 6/3/2011 Page 1 of 3

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-4 - Level 3 Low NOx Burners with SOFA and Selective Non-Catalytic Reduction 

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0 Chemical Engineering

Design Capacity 274.1 Standardized Flow Rate 71,856 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 80% Temperature 145 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,760 Hours Moisture Content 4.0% Jul-10 550.7

Annual Interest Rate 7.0% Actual Flow Rate 82,335 acfm Inflation Adj 1.41

Expected Equipment Life 20 yrs Standardized Flow Rate 77,114 scfm @ 68o F

Dry Std Flow Rate 59,033 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year

 Direct Capital Costs EPRI Correlation, 1998 $'s 274 25% 0.40 1998 NA

 Purchased Equipment (A) 2010 NA

 Purchased Equipment Total (B) 0% of control device cost (A) NA

 Installation - Standard Costs 15% of purchased equip cost (B) 0

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC 4,531,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 248,268

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 649,713

Total Annual Cost (Annualized Capital Cost + Operating Cost) 897,981

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 101.4 355.3 38% 0.23 lb NOx/MMbtu 220.9 134.5 6,679

Sulfur Dioxide (SO2) 220.1 771.2 771.2 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 "Conceptual Design Study for NOx Reduction Tehcnologies" March, 2011 A site specifice enginieering and cost evaluation prepared by Sargent and Lundy, LLC 

2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22

3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25

4 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29

5 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23

6 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C2 23MW NOx Control Cost Worksheets 050611.xlsx

NOx LNB&SNCR S&L 6/3/2011 Page 2 of 3

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-4 - Level 3 Low NOx Burners with SOFA and Selective Non-Catalytic Reduction 

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) 

Purchased Equipment Costs (A) NA

Instrumentation 10% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) NA

Indirect Installation

General Facilities 5% of purchased equip cost (A) NA

Engineering & Home Office 10% of purchased equip cost (A) NA

Process Contingency 5% of purchased equip cost (A) NA

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) NA

Project Contingency ( C) 15% of (A + B) 0

SNCR Equipment Subtotal NA

Total Plant Cost D A + B + C 0

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 0

Inventory Capital Reagent Vol * $/gal 0

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) (1) 4,531,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 4,531,000

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total (5) 1.50 1.5% of Total Capital Investment 67,965

NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh, 4 kW-hr, 8760 hr/yr, 80% utilization 1,766

Natural Gas 6.85 $/mscf, 1 scfh, 8760 hr/yr, 80% utilization 25,914

Water 1.16 $/mgal, 33 gph, 8760 hr/yr, 80% utilization 265

NA

NA

NA

NA NA - 

NA NA - 

NA NA - 

NA NA - 

SW Disposal 32.62 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization 485

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Urea 50% Solution 637.60 $/ton , 0 ton/hr, 8760 hr/yr, 80% utilization 151,874

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 248,268

Indirect Operating Costs

Overhead 60% of total labor and material costs 40,779

Administration (2% total capital costs) 2% of total capital costs (TCI) 90,620

Property tax (1% total capital costs) 1% of total capital costs (TCI) 45,310

Insurance (1% total capital costs) 1% of total capital costs (TCI) 45,310

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 427,694

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 649,713

Total Annual Cost (Annualized Capital Cost + Operating Cost) 897,981

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C2 23MW NOx Control Cost Worksheets 050611.xlsx

NOx LNB&SNCR S&L 6/3/2011 Page 3 of 3

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-4 - Level 3 Low NOx Burners with SOFA and Selective Non-Catalytic Reduction 

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst <- Enter Equipment Name to Get Cost

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 214 $/ft3

Amount Required 12 ft3

Packing Cost 2,700 Cost adjusted for freight

Installation Labor 405 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 650 $/ft3

Amount Required 0 Cages

Total Rep Parts Cost 0 Cost adjusted for freight See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr)

Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag.

Annualized Cost 0

Electrical Use (5)

NOx in 0.40 lb/MMBtu kW

NSR 0.82

Power 4.4

Total 4.4

Reagent Use & Other Operating Costs Urea Use (2)

NOx in 0.40 lb/MMBtu 34 lb/hr Neat 0.02

Efficiency 25% 50% solution 71.0 lb/ft3 Density 50% Solution

Duty 274 MMBtu/hr 68 lb/hr 7.2 gal/hr

Volume 14 day inventory 2,407 gal $7,282 Inventory Cost

Water Use (3) 33 gal/hr Inject at 10% solution

Fuel Use (4) 0.6 MMBtu/hr 0.5 mscfh natural gas

Ash Generation 4.2 lb/hr

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.50 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA - 15% of Operator Costs

Maintenance

Maintenance Total (5) 1.5 % of Total Capital Investment 67,965 1.5% of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 4.4 kW-hr 30,987 1,766 $/kwh, 4 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 0.5 scfh 3,783 25,914 $/mscf, 1 scfh, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 32.6 gph 228 265 $/mgal, 33 gph, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air 0.37 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatement 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal 32.62 $/ton 0.002 ton/hr 15 485 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 326.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Transport 0.65 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Lime 86.95 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

Urea 50% Solution 637.60 $/ton 0.0340 ton/hr 238 151,874 $/ton , 0 ton/hr, 8760 hr/yr, 80% utilization

Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

SCR Catalyst 214.285714 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

CO Catalyst 650 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C2 23MW NOx Control Cost Worksheets 050611.xlsx

NOx SNCR S&L 6/3/2011 Page 1 of 3

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-5 - Selective Non-Catalytic Reduction 

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0 Chemical Engineering

Design Capacity 274.1 Standardized Flow Rate 71,856 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 80% Temperature 145 Deg F 1998/1999 NA

Expected Annual Hours of Operation 8,760 Hours Moisture Content 4.0% Jul-10 NA

Annual Interest Rate 7.0% Actual Flow Rate 82,335 acfm Inflation Adj NA

Expected Equipment Life 20 yrs Standardized Flow Rate 77,114 scfm @ 68o F

Dry Std Flow Rate 59,033 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year

 Direct Capital Costs EPRI Correlation, 1998 $'s 274 25% 0.40 1998 NA

 Purchased Equipment (A) 2010 NA

 Purchased Equipment Total (B) 0% of control device cost (A) NA

 Installation - Standard Costs 15% of purchased equip cost (B) 0

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC 2,433,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 216,798

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 348,875

Total Annual Cost (Annualized Capital Cost + Operating Cost) 565,673

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 101.4 355.3 16% 0.31 lb NOx/MMbtu 297.7 57.6 9,817

Sulfur Dioxide (SO2) 220.1 771.2 771.2 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 "Conceptual Design Study for NOx Reduction Tehcnologies" March, 2011 A site specifice enginieering and cost evaluation prepared by Sargent and Lundy, LLC 

2 Reagent Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.22

3 Water use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.25

4 Additional Fuel Use per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.29

5 SNCR Electrical Demand per EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.23

6 SNCR Maintenance Costs EPA Air Pollution Control Cost Manual 6th Ed 2002, Section 4.2 Chapter 1 Eq 1.21
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C2 23MW NOx Control Cost Worksheets 050611.xlsx

NOx SNCR S&L 6/3/2011 Page 2 of 3

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-5 - Selective Non-Catalytic Reduction 

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) 

Purchased Equipment Costs (A) NA

Instrumentation 10% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) NA

Indirect Installation

General Facilities 5% of purchased equip cost (A) NA

Engineering & Home Office 10% of purchased equip cost (A) NA

Process Contingency 5% of purchased equip cost (A) NA

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) NA

Project Contingency ( C) 15% of (A + B) 0

SNCR Equipment Subtotal NA

Total Plant Cost D A + B + C 0

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 0

Inventory Capital Reagent Vol * $/gal 0

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) (1) 2,433,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 2,433,000

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator NA - 

Supervisor NA - 

Maintenance

Maintenance Total (6 1.50 1.5% of Total Capital Investment 36,495

NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh, 4 kW-hr, 8760 hr/yr, 80% utilization 1,766

Natural Gas 6.85 $/mscf, 1 scfh, 8760 hr/yr, 80% utilization 25,914

Water 1.16 $/mgal, 33 gph, 8760 hr/yr, 80% utilization 265

NA

NA

NA

NA NA - 

NA NA - 

NA NA - 

NA NA - 

SW Disposal 32.62 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization 485

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Urea 50% Solution 637.60 $/ton , 0 ton/hr, 8760 hr/yr, 80% utilization 151,874

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 216,798

Indirect Operating Costs

Overhead 60% of total labor and material costs 21,897

Administration (2% total capital costs) 2% of total capital costs (TCI) 48,660

Property tax (1% total capital costs) 1% of total capital costs (TCI) 24,330

Insurance (1% total capital costs) 1% of total capital costs (TCI) 24,330

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 229,658

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 348,875

Total Annual Cost (Annualized Capital Cost + Operating Cost) 565,673

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C2 23MW NOx Control Cost Worksheets 050611.xlsx

NOx SNCR S&L 6/3/2011 Page 3 of 3

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-5 - Selective Non-Catalytic Reduction 

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst <- Enter Equipment Name to Get Cost

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 214 $/ft3

Amount Required 12 ft3

Packing Cost 2,700 Cost adjusted for freight

Installation Labor 405 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 650 $/ft3

Amount Required 0 Cages

Total Rep Parts Cost 0 Cost adjusted for freight See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr)

Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag.

Annualized Cost 0

Electrical Use (5)

NOx in 0.40 lb/MMBtu kW

NSR 0.82

Power 4.4

Total 4.4

Reagent Use & Other Operating Costs Urea Use (2)

NOx in 0.40 lb/MMBtu 34 lb/hr Neat 0.02

Efficiency 25% 50% solution 71.0 lb/ft3 Density 50% Solution

Duty 274 MMBtu/hr 68 lb/hr 7.2 gal/hr

Volume 14 day inventory 2,407 gal $7,282 Inventory Cost

Water Use (3) 33 gal/hr Inject at 10% solution

Fuel Use (4) 0.6 MMBtu/hr 0.5 mscfh natural gas

Ash Generation 4.2 lb/hr

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.50 $/Hr hr/8 hr shift 0 0 $/Hr, 0.0 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA - 15% of Operator Costs

Maintenance

Maintenance Total (6 1.5 % of Total Capital Investment 36,495 1.5% of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 4.4 kW-hr 30,987 1,766 $/kwh, 4 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 0.5 scfh 3,783 25,914 $/mscf, 1 scfh, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 32.6 gph 228 265 $/mgal, 33 gph, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air 0.37 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatement 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal 32.62 $/ton 0.002 ton/hr 15 485 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 326.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Transport 0.65 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Lime 86.95 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

Urea 50% Solution 637.60 $/ton 0.0340 ton/hr 238 151,874 $/ton , 0 ton/hr, 8760 hr/yr, 80% utilization

Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

SCR Catalyst 214.285714 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

CO Catalyst 650 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C2 23MW NOx Control Cost Worksheets 050611.xlsx

NOx LNB S&L 6/3/2011 Page 1 of 3

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-6 - Level 3 Low NOx Burners with Separated Overfire Air (SOFA)

Operating Unit: NA

Design Capacity 48 MW Stack/Vent Number 0 Chemical Engineering

Design Capacity 274.1 Standardized Flow Rate 71,856 scfm @ 32o F Chemical Plant Cost Index

Expected Utilization Rate 80% Temperature 145 Deg F 1998/1999 390

Expected Annual Hours of Operation 8,760 Hours Moisture Content 4.0% Jul-10 550.7

Annual Interest Rate 7.0% Actual Flow Rate 82,335 acfm Inflation Adj 1.41

Expected Equipment Life 20 yrs Standardized Flow Rate 77,114 scfm @ 68o F

Dry Std Flow Rate 59,033 dscfm @ 68o F

CONTROL EQUIPMENT COSTS

Capital Costs Duty MMBtu/hr Control Eff NOx in lb/MMBtu Year

 Direct Capital Costs EPRI Correlation, 1998 $'s 274 25% 0.40 1998 NA

 Purchased Equipment (A) 2010 NA

 Purchased Equipment Total (B) 0% of control device cost (A) NA

 Installation - Standard Costs 15% of purchased equip cost (B) 0

 Installation - Site Specific Costs 0

 Installation Total 0

 Total Direct Capital Cost, DC 0

 Total Indirect Capital Costs, IC 0% of purchased equip cost (B) 0

Total Capital Investment (TCI) = DC + IC 2,195,000

Operating Costs

 Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 43,471

 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 321,075

Total Annual Cost (Annualized Capital Cost + Operating Cost) 364,546

Emission Control Cost Calculation

Max Emis Annual Cont Eff Exit Conc. Cont Emis Reduction Cont Cost

Pollutant Lb/Hr T/Yr % Conc. Units T/yr T/yr $/Ton Rem

PM10 - - 0.0 - NA

Total Particulates - - 0.0 - NA

Nitrous Oxides (NOx) 101.4 355.3 30% 0.26 lb NOx/MMbtu 249.7 105.6 3,451

Sulfur Dioxide (SO2) 220.1 771.2 771.2 - NA

Sulfuric Acid Mist - - 0.0 - NA

Fluorides - - 0.0 - NA

Volatile Organic Compounds (VOC) - - 0.0 - NA

Carbon Monoxide (CO) 53.8 188.4 188.4 - NA

Lead (Pb) - - 0.0 - NA

Notes & Assumptions

1 "Conceptual Design Study for NOx Reduction Tehcnologies" March, 2011 A site specifice enginieering and cost evaluation prepared by Sargent and Lundy, LLC 
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C2 23MW NOx Control Cost Worksheets 050611.xlsx

NOx LNB S&L 6/3/2011 Page 2 of 3

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-6 - Level 3 Low NOx Burners with Separated Overfire Air (SOFA)

CAPITAL COSTS

Direct Capital Costs

Purchased Equipment (A) 

Purchased Equipment Costs (A) NA

Instrumentation 10% of control device cost (A) NA

Freight 5% of control device cost (A) NA

Purchased Equipment Total (A) NA

Indirect Installation

General Facilities 5% of purchased equip cost (A) NA

Engineering & Home Office 10% of purchased equip cost (A) NA

Process Contingency 5% of purchased equip cost (A) NA

Total Indirect Installation Costs (B) 20% of purchased equip cost (A) NA

Project Contingency ( C) 15% of (A + B) 0

SNCR Equipment Subtotal NA

Total Plant Cost D A + B + C 0

Allowance for Funds During Construction (E) 0 for SNCR 0

Royalty Allowance (F) 0 for SNCR 0

Pre Production Costs (G) 2% of (D+E)) 0

Inventory Capital Reagent Vol * $/gal 0

Initial Catalyst and Chemicals 0 for SNCR 0

Total Capital Investment (TCI) 1 2,195,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 2,195,000

OPERATING COSTS

Direct Annual Operating Costs, DC

Operating Labor

Operator 33.50 $/Hr, 0.3 hr/8 hr shift, 8760 hr/yr 9,171

Supervisor 15% 15% of Operator Costs 1,376

Maintenance

Maintenance Total 1.50 1.5% of Total Capital Investment 32,925

NA % of Maintenance Labor - 

Utilities, Supplies, Replacements & Waste Management

NA NA - 

NA NA - 

NA NA - 

NA

NA

NA

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

NA NA - 

Total Annual Direct Operating Costs 43,471

Indirect Operating Costs

Overhead 60% of total labor and material costs 26,083

Administration (2% total capital costs) 2% of total capital costs (TCI) 43,900

Property tax (1% total capital costs) 1% of total capital costs (TCI) 21,950

Insurance (1% total capital costs) 1% of total capital costs (TCI) 21,950

Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 207,192

Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 321,075

Total Annual Cost (Annualized Capital Cost + Operating Cost) 364,546

See Summary page for notes and assumptions
P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\MDU L&C Regional Haze Eval\WorkFiles\Appendix C2 23MW NOx Control Cost Worksheets 050611.xlsx

NOx LNB S&L 6/3/2011 Page 3 of 3

Appendix C.2 - February 2011 Regional Haze Evaluation for 

Lewis and Clark Generating Station, Montana Dakota Utilities 23MW Case

Table C.2-6 - Level 3 Low NOx Burners with Separated Overfire Air (SOFA)

Capital Recovery Factors

Primary Installation

Interest Rate 7.00%

Equipment Life 20 years

CRF 0.0944

Replacement Catalyst <- Enter Equipment Name to Get Cost

Equipment Life 5 years

CRF 0.2439

Rep part cost per unit 214 $/ft3

Amount Required 12 ft3

Packing Cost 2,700 Cost adjusted for freight

Installation Labor 405 Assume Labor = 15% of catalyst cost (basis labor for baghouse replacement)

Total Installed Cost 0 Zero out if no replacement parts needed

Annualized Cost 0

Replacement Parts & Equipment: <- Enter Equipment Name to Get Cost

Equipment Life 2 years

CRF 0.0000

Rep part cost per unit 650 $/ft3

Amount Required 0 Cages

Total Rep Parts Cost 0 Cost adjusted for freight See Control Cost Manual Sec 6 Ch 1 Table 1.8 for bag costs

Installation Labor 0 10 min per bag, Labor + Overhead (68% = $29.65/hr)

Total Installed Cost 0 Zero out if no replacement parts needed EPA CCM list replacement times from 5 - 20 min per bag.

Annualized Cost 0

Electrical Use

NOx in 0.40 lb/MMBtu kW

NSR 0.82

Power 4.4

Total 4.4

Reagent Use & Other Operating Costs Urea Use

NOx in 0.40 lb/MMBtu NA lb/hr Neat NA

Efficiency NA 50% solution 71.0 lb/ft3 Density 50% Solution

Duty 274 MMBtu/hr NA lb/hr NA gal/hr

Volume 14 day inventory NA gal NA Inventory Cost

Water Use NA gal/hr Inject at 10% solution

Fuel Use NA MMBtu/hr NA mscfh natural gas

Ash Generation NA lb/hr

Operating Cost Calculations Annual hours of operation: 8,760

Utilization Rate: 80.0%

Unit Unit of Use Unit of Annual Annual Comments

Item Cost $ Measure Rate Measure Use* Cost

Operating Labor

Op Labor 33.50 $/Hr 0.3 hr/8 hr shift 274 9,171 $/Hr, 0.3 hr/8 hr shift, 8760 hr/yr

Supervisor 15% of Op. NA 1,376 15% of Operator Costs

Maintenance

Maintenance Total 1.5 % of Total Capital Investment 32,925 1.5% of Total Capital Investment

Maint Mtls 0 % of Maintenance Labor NA 0 0% of Maintenance Labor

Utilities, Supplies, Replacements & Waste Management

Electricity 0.057 $/kwh 0.0 kW-hr 0 0 $/kwh, 0 kW-hr, 8760 hr/yr, 80% utilization

Natural Gas 6.85 $/mscf 0.0 scfh 0 0 $/mscf, 0 scfh, 8760 hr/yr, 80% utilization

Water 1.16 $/mgal 0.0 gph 0 0 $/mgal, 0 gph, 8760 hr/yr, 80% utilization

Cooling Water 0.32 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

Comp Air 0.37 $/mscf 0.0 scfm/kacfm** 0 0 $/mscf, 0 scfm/kacfm**, 8760 hr/yr, 80% utilization

WW Treat Neutralization 1.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

WW Treat Biotreatement 4.96 $/mgal 0.0 gpm 0 0 $/mgal, 0 gpm, 8760 hr/yr, 80% utilization

SW Disposal 32.62 $/ton 0.000 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Haz W Disp 326.19 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

Waste Transport 0.65 $/ton-mi 0.0 ton/hr 0 0 $/ton-mi, 0 ton/hr, 8760 hr/yr, 80% utilization

0.00 $/ton 0.0 ton/hr 0 0 $/ton, 0 ton/hr, 8760 hr/yr, 80% utilization

1 Lime 86.95 $/ton 0.0 lb/hr 0 0 $/ton, 0 lb/hr, 8760 hr/yr, 80% utilization

6 Urea 50% Solution 637.60 $/ton 0.0000 ton/hr 0 0 $/ton , 0 ton/hr, 8760 hr/yr, 80% utilization

5 Trona 158.45 Mscf 0.0 Mscf/hr 0 0 Mscf, 0 Mscf/hr, 8760 hr/yr, 80% utilization

1 SCR Catalyst 214.285714 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

2 CO Catalyst 650 $/ft3 0 ft3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization

** Std Air use is 2 scfm/kacfm *annual use rate is in same units of measurement as the unit cost factor

See Summary page for notes and assumptions
Appendix D

Coal Variability Data
Coal Variability

Poor coal quality is indicated by low btu content and calcium content and high sulfur content, ash 

content, and moisture content. As illustrated in the figures below, trends in past coal characteristics

indicate a steady decrease in expected quality for Unit 1’s coal supply on an annual basis, with a high 

degree of variability observed on a short term basis.

Weekly analytical results for various coal properties are presented below. The figures also include 

monthly and annual averages of the weekly data. A total of 567 samples are included for date ranges 

from January 2000 through November 20101. Data is presented on an as-received basis and is not 

moisture corrected.

 Figure D1. Coal Energy Content Data

The data presented illustrates a range in energy content from approximately 5,900 btu to 7,500 

btu. From 2005 through present, there is a clear trend toward decreased energy content on an 

annual basis.

 Figure D2. Coal Sulfur Content Data

The data presented illustrates a range in sulfur content of approximately 0.2% to 1.4%. Coal 

sulfur content is highly variably on a weekly basis, with average sulfur content maintaining a 

range of 0.4% to 0.6%.

 Figure D3. Coal Calcium Content Data

The data presented illustrates a range in calcium content of approximately 6% to 27%. Calcium 

results are highly variable on a weekly basis, and demonstrate a slight decrease in average 

calcium content on an annual basis.

 Figure D4. Coal Ash Content Data

The data presented illustrates a range in moisture content of approximately 9% to 15%. From 

2005 through present, there is a clear trend toward increased ash content on an annual basis.

 Figure D5. Coal Moisture Content Data

The data presented illustrates a range in moisture content of approximately 28% to 40%. From 

2005 through present, there is a clear trend toward increased moisture content on an annual 

basis.

 

1

Analytical data for calcium is available from April 2006 through November 2010.
5900

6100

6300

6500

6700

6900

7100

7300

7500

Dec 1999 Apr 2001 Sep 2002 Jan 2004 May 2005 Oct 2006 Feb 2008 Jul 2009 Nov 2010

Average Energy Content (btu)

Year

Figure D1. Coal Energy Content Data

Weekly

Monthly

Annual
0.20

0.40

0.60

0.80

1.00

1.20

1.40

Dec 1999 Apr 2001 Sep 2002 Jan 2004 May 2005 Oct 2006 Feb 2008 Jul 2009 Nov 2010

Average Sulfur Content (%)

Year

Figure D2. Coal Sulfur Content Data

Weekly

Monthly

Annual
5

10

15

20

25

30

Apr 2006 Oct 2006 May 2007 Dec 2007 Jun 2008 Jan 2009 Jul 2009 Feb 2010 Aug 2010

AverageCalcium Content (%)

Year

Figure D3. Coal Calcium Content Data

Weekly

Monthly

Annual
6

7

8

9

10

11

12

13

14

15

Dec 1999 Apr 2001 Sep 2002 Jan 2004 May 2005 Oct 2006 Feb 2008 Jul 2009 Nov 2010

Average Ash Content (%)

Year

Figure D4. Coal Ash Content Data

Weekly

Monthly

Annual
28

30

32

34

36

38

40

Dec 1999 Apr 2001 Sep 2002 Jan 2004 May 2005 Oct 2006 Feb 2008 Jul 2009 Nov 2010

Average Moisture Content (%)

Year

Figure D5. Coal Moisture Content Data

Weekly

Monthly

Annual
Appendix E

General Arrangement Drawing


Appendix F

Ammonia Slip Water Impacts
Water Impacts of Ammonia Slip Calculation

Water impacts of SNCR are based on a design ammonia slip range of 5 to 10 ppm. Using this range in 

combination with Equation 1 below, an SNCR ammonia exhaust rate of 2.14 lb/hr to 4.27 lb/hr was 

calculated.

Equation 1

NH3 Slip (ppm) = NH3 Rate �

lb

hr

� ×

1 hr

60 min

×

1 lb − mol

17.03 lb ×

385 scf

lb − mol ×

min

160,934 scf ×

106parts

million

Where:

NH3 Slip = Design basis ammonia slip range (ppm)

NH3 Rate = SNCR emitted ammonia rate (lb/hr)

160,934 = Unit 1 exhaust flow rate based on June 9, 2010 stack testing

17.03 = Molecular weight of ammonia

385 = Volumetric flow conversion factor at standard conditions

To determine the final effluent concentrations, the predicted ammonia exhaust rates were combined 

with facility specific flow data as illustrated in Equation 2. Effluent ammonia concentrations are 

calculated to be 8.4 mg/L to 16.7 mg/L.

Equation 2

NH3 �

mg

L � = �NH3 Rate �

lb

hr

� ×

453,592 mg

lb � ÷ �

510 gal

min

×

60 min

hr

×

3.79 L

gal �

Where:

NH3 = Effluent ammonia concentration (mg/L)

510 = Effluent flow rate from 2006 water quality testing at L&C

453,592 & 510 = standard mass and volume conversions

As stated in the Montana DEQ Water Quality Circulari

 i

Excerpt from Circular DEQ-t (August 2010), Page 11.

, the standard for ammonia is no detectable 

concentration, with a trigger value of 10 mg/L. As demonstrated in the calculations above, installation of 

SNCR with standard ammonia slip design parameters has the potential to adversely impact effluent 

ammonia concentrations.
Appendix F

Ammonia Slip Water Impacts