# 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

4700 West 77 th Street Minneapolis, MN 55435

- 4803 Phone: (952) 832

- 2600 Fax: (952) 832

- 2601

### i



## Emissions Control Analysis for Lewis & Cla rk 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 Lim its

............................................................................... 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 SO 2 

### Control Evaluation

................................................................ ........................................................ 12
5.1 SO 2 

### Con trol 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 SO 2 

### Control Strategy

................................................................................................ . 16 6.0 NOx Control Evaluation

................................................................ ....................................................... 18
6.1 NOx Co ntrol 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

### ii List of Tables

Table 1. Control Effectiveness of Technically Feasible SO 2 

### Control Options

................................... 14 Table 2. SO 2 

### Control Cost Summary

................................................................................................ . 15 Table 3. SO 2 

### 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 d ry -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 ( CC OFA) for NOx control. The particulate scrubber also achieves nominal
SO 2 

### 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 SO 2 

### 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.

 SO 2 

### emissions will be reduced by optimizing the existing particulate scrubber and lime injection system to achieve a total SO 2 

### 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 tha t 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 regardi ng 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 d ry -bottom, tangential ly -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 (SO 2 

### ) : Permit limit of 2.0 lb SO 2 

### /MMBtu

The flooded-disc wet scrubber is designed for particulate control with a nominal SO 2 

### control efficiency of approximately 15%

. In practice, up to 60% SO 2 

### 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 a ir ( CC OFA) 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/PM 10 

### 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 Manual 1 

### . 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 analyse s 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).

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.

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 SO 2 

### 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

Figure 1. Historical Coal Energy Content (Btu)

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 quality 2 

### 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.

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 SO 2 

### 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.

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 SO 2 

### 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 SO 2 

# Control Evaluation

Unit 1 currently controls SO 2 

### emissions through calcium concentrations present in the incoming coal. In addition, lime can be added to the wet particulate scrubber to enhance SO 2 

### removal when the coal has lower calcium content and higher sulfur content

. Per EPA’s request 3 

### , a list of SO 2 

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

 Lime Spray Dry er Absorber (SDA) and Baghouse

 Dry Sorbent Injection (DSI) and Baghouse

 Optimizations of Existing Wet PM Scrubber 3


### 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 SO 2 

## Control Technology Descriptions The FGD systems commonly used to control SO 2 

### 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 SO 2 

### control, however, they are significantly more expensive. Generally, it takes one molecule of reagent to capture one SO 2 

### molecule; a stoichiometric ratio of 1. Wet FGD systems generally operate at a stoichiometric ratio of 1.1:1 (reagent: SO 2 - 

### i.e. 10% extra

re agent). Dry FGD systems require stoichiometric ratios of 1.3:1 or higher to achieve optimal SO 2 

### 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 e quivalent 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 Dry er 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 SO 2 

### is absorbed by the droplets. Once absorbed, the SO 2 

### reacts with lime to form calcium sulfite (CaSO 3 

### •2H 2 

### O) and calcium sulfate (CaSO 4 

### ) 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 SO 2 

### . 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 SO 2 

### in the gas stream reacts with the lime to form calcium sulfite (CaSO 3 

### • 2H 2 

### O) and calcium sulfate (CaSO 4 

### ).

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 SO 2 

### removal.

Modifications to the existing PM wet scrubber to increase SO 2 

### 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 SO 2 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. 7 0 % 0.4 5 901.9 100.2 DSI with Baghouse 70 % 0.4 5 901.9 100.2
Baseline Emissions NA 0.5 0 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

. SO 2 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 $9. 6 8 $11,390 $12,776 Existing Scrubber Mod. $0.27 $0.1 0 $1,015 NA DSI with Baghouse $15.75 $2.80 $27,912 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
SO 2 

### 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 SO 2 

### 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

. SO 2 Control Technology Impacts Summary



### Control Option Energy Impacts Other Impacts Economic Impacts
SDA Baghouse Blower requires

increased energy use and associated indirect CO 2 

### 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 ($ 11,390 ) and incremental ($ 12,776 ) 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 in cluded in scrubber optimization study. Economically feasible on both an average ($1,015) cost per ton basis.

DSI Baghouse Blower requires

increased energy use and associated indirect CO 2 

### 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 ($ 27,912 ) cost per ton basis

.



## 5.3 Proposed SO 2 

## 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
SO 2 

### 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 SO 2 

### 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 SO 2 

### 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 SO 2 

### 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 SO 2 

### 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:
N 2 

### + O 2 

###  2NO (1) Downstream of the flame, significant amounts of NO 2 

### can be formed when NO is mixed with air. The
reaction is as follows:
2NO + O 2 

###  2NO 2 

### (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 ( CC OFA) system

. Per EPA’s request 4 

### , a list of NOx control options considered in this RP evaluation is presented below:

 Combustion Controls

o Separated Overfire Air (SOFA)

o Low NOx Burners

 Post-Combustion Controls

o Selective Catalytic Reduction (SCR)

o Selective Non- Ca talytic 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 (N 2 

### ) 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 (NH 3 

### ) 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 + 4NH 3 

### + O 2 

###  4N 2 

### + 6H 2 

### 0 (1)
2NO 2 

### + 4NH 3 

### + O 2 

###  3N 2 

### + 6H 2 

### 0 (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 NH 3 

### 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 NH 3 

### is present in the system. Depending on SCR installation in relation to existing controls, ammonia slip can generally cause additional NH 3 

### to be emitted to air or water. As NH 3 

### 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 Station 5 

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

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)

### 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 

### 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.

Selective Non-Catalytic Reduction (SNCR) 

### In the SNCR process, urea or ammonia-based chemicals are injected into the flue gas stream to convert NO to molecular nitrogen, N 2 

### , 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 + NH 3 

### + 1⁄4O 2 

###  N 2 

### + 3/2H 2 

### O (1)

NH 3 

### + 1⁄4O 2 

###  NO + 3/2H 2 

### O (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 bi sulfate from the air heaters which would impact the cost per ton values presented
below.


## 6.2 Summary of Evaluated Factors
Based on the current utilization 7 

### and design degree of control being achieved on Unit 1, Table 4
de scribes 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 S OFA/LNB 50% 0.20 400.9 400.9 S OFA/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 load 8 

### ) 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 $18,786
SNCR with S OFA/LNB $3.69 $0.96 $2,395 $7,279
SOFA/LNB $1.35 $0.23 $767 NA
SNCR $2.43 $0.76 $2,533 NA SNCR (low load) $2.43 $0. 56 $9,8 1 7 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/L 9 

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

9 Circular DEQ -7 Montana Numerical Water Quality Standards. MDEQ Planning, Prevention, and Assistance Division - Water Quality Standards Section. August 2010.

### 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

- R eheat potentially

required to make SCR technically feasible will result in high energy use and associated costs along with increased CO 2 

### emissions

. 1. S pent 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 ($18,786 ) cost per ton basis.

SOFA /LNB

- Minimal energy impacts. 1. I ncrease in CO emissions. Any CO increase may require permitting actions and approval from M T DEQ

. Economically feasible on an average ($ 767 ) 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 i ncrease in CO emissions. Any CO increase may require permitting actions and approval from M T DEQ ( due to SOFA /LNB). Economically infeasible on an incremental ($ 7,279 ) basis and marginally feasible on an average ($2,533 ) cost per ton basis. Economically inf easible at low load operation on an average basis ($ 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 SO 2 

### 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 SO 2 

### 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.

 SO 2 

### – Optimization of the existing PM wet scrubber to further reduce SO 2 

### emissions is proposed. Continuous lime injection system configuration is being developed, and upon installation, an optimization study will be conducted to determine sustainable SO 2 

### 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 SO 2 

### 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 SO 2 

### 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
SO 2 

### 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 LetterUNITED STATES ENVIRONMENTAL PROTE CTI ON AGENC Y REGION 8



### Ref : 8P-AR 1595 Wynkoop St r eet DENVER
, CO 80202-1129 Phone 800

- 227-8917 http :// www

. epa .g ov / r egion08



### CERTIFIED MAIL

- RET U RN RECEIPT REQ UE STED

Abbie Krebsbach Environmental Manager Montana-Dakota U tilitie s Co mpan y 400 North Fourth Street Bi s marck
, No rth Dakota 58501

Dear Ms. Krebsbach: RE: Reque s t for Additional Rea so nable Progres s I nformation for the Montana-Dakota Utilities Company, Lewis and Cla r k Generating Station, Pursuant to Section 114(a) of the C l ean Air Act (42 U.S.c. Section 7414(a))

As yo u kn ow, on July 19 ,200 6 , the Environmenta l Protection Agency (EPA) received a letter from the Montana D e pamnent of E n v ironmental Quality (MDEQ) that s tated it wa s withdrawing its efforts to adopt a s tate implementation p l an (SIP) for regiona l haze under EPA 's Regional Haze Rule ( RHR). found at 40 CF R 51.308

. Due to Montana 's announcement that it would not be addressing the requirement s under 40 CFR 51.308
, E PA Region 8 i s moving forward with the technical a nd policy work needed to implement the requirement s of the RHR under a Federal implementation plan (FIP). See Section 110(c)(I ) of th e C lean Air Act (CAA), 42 U

. S.C . § 7410 ( c)(I).

As part of our effort to address requirement s under the RHR for reasonable progre ss (RP) goals and s trategie s (see 40 CFR 51.308(d)( I) and 51.308(d)(3))
, we previously reque s t e d information regarding th e Montana-Dakota Uti litie s Company
, Lewis and Clark Generating Station. We have reviewed the information that you submitted dated March 17
, 2009 in respon se to our January 29, 2009 CAA Section 114 information request on the emission unit at yo ur facility. Ba se o on the emissions and current control technology information yo u s ubmitted
, emissions unit I (a tangential coal/natural gas boi l er) is a source that warrants further analysis in considering and developing s trate g ies for achieving the RP goal for Montana.

Plea se submit an analysis of control options for this unit postmarked within 60 days of th e date of this letter. The analysis mu s t address the four factor s included in 40 CF R 

### § 51.308(d)( I )(i)(A)

- the costs of compliance
, the tim e neces sa ry for compliance
, the

### energy and non-air quality environmenta l impacts of comp liance
, and the remaining useful life of the potentially affected sources. We suggest that the Best Avai labl e Retrofit Techno l ogy (BART) G uidel ines (see 40 CFR Part 51 Appendix Y) provide additional guidance on how to perform the cost of compliance portion of this analysis. You r ana l ysis must consider the full range ofava il ab le control technologie s and for eac h technology
, you must consider the full range of emission sta ndard s including th e most str in gent.

We under stand this is a complicated endeavo r , and we are available to answer any questions that you may ha ve on the RHR or the RP ana l ys i s. We wi ll assist you in any way we
can and l ook forward to working with you.

Pursuant to Section 114 of the C l ean A ir Act, 42 U.S.C. §7414
, and under authority duly delegated to the undersigned
, you are required to provide us with the information s pecified in this letter. Th i s information will be used by EPA in deve l oping a regional haze FIP, or in the event MDEQ resumes development of a regional ha ze SIP, in assisting MDEQ in that effort and / or reviewing a regional haze SIP for Montana. Furthermore, information request s pursuant to Section 114 of the CAA are not limited to so urces that are regulated by the particu l ar rule EPA is implementing. For example
, Section 114 (a)( I ) says that EPA may gather information from "any person w h o owns or operates any emission source" or "w ho the Adm ini strator believes may have information necessary for the purposes se t 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 repre se ntation s on beha l f of Montana -D akota Utilities Company.

Please subm it your respon se 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 Ut iliti es Company i s entitled to assert a busine ss confidentiality claim covering any part of the submitted information. Attachment B specified the assel1ion and

s ub sta ntiation requirements for bu si nes s confidentiality claims. Failure to assert s uch a claim makes the submitted information s ubject to public disclosure upon request and without further notice to yo u , pursuant to the Freedom of Information Act
, 5 U

. S

. c. Section 552. Information

s ubject 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 reque s t 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 s heet.

The requirements of this letter are not subject to the Paperwork Reduction Act of 1980
, 44 U.S.c. §3501 e l seq.



### We appreciate your cooperation in this matter. If you have any question s please call Vane s sa Hinkle of my staff at 303-312-6561.

Enclo s ures

cc: John Bunyak. NPS Sandra Silva
, USFWS Thomas D z omba
, 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 R esources Management Bureau (406) 444

- 9741 Shawn Juers Environmental Engineer Air Resources Management Bureau (406) 444

- 2049

VW: SJ Enclosure

c c: Christopher Ajayi, US EPA Region VIII 8P- AR Carson Coate, US EPA Region VIII, Montana OfficeOP0691-05 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. F ACILITY 

### -W IDE



### ........................................................................................................................... 3 B. EU01: T ANGENTIAL 

### C OAL 

### -F IRED 

### B OILER 

### (C OAL AND 

### N ATURAL 

### G AS 

### ) .................................... 6 C. EU06: F UEL 

### ( GASOLINE 

### ) S TORAGE 

### T ANK



### ................................................................................ 10 D. EU07: C OAL 

### S TORAGE 

### P ILES



### ................................................................................................... 10 E. EU08: F UGITIVE 

### C OAL 

### , A SH 

### , AND 

### L IME 

### H ANDLING



### ................................................................ 12


### SECTION IV. NON-APPLICABLE REQUIREME NTS

............................................................... 14
A. F ACILITY 

### -W IDE



### ......................................................................................................................... 14 B. E MISSION 

### U NITS



### ........................................................................................................................ 15


### SECTION V. GENERAL PERMIT CONDITIONS ......................................................................... 16
A. C OMPLIANCE 

### R EQUIREMENTS



### ................................................................................................... 16 B. C ERTIFICATION 

### R EQUIREMENTS



### ............................................................................................... 16 C. P ERMIT 

### S HIELD



### ......................................................................................................................... 17 D. M ONITORING 

### , R ECORDKEEPING 

### , AND 

### R EPORTING 

### R EQUIREMENTS



### ......................................... 18 E. P ROMPT 

### D EVIATION 

### R EPORTING



### ............................................................................................... 19 F. E MERGENCY 

### P ROVISIONS



### .......................................................................................................... 19 G. I NSPECTION AND 

### E NTRY



### ........................................................................................................... 20 H. F EE 

### P AYMENT



### ........................................................................................................................... 20 I. M INOR 

### P ERMIT 

### M ODIFICATIONS



### ............................................................................................... 21 J. C HANGES 

### N OT 

### R EQUIRING 

### P ERMIT 

### R EVISION



### .......................................................................... 21 K. S IGNIFICANT 

### P ERMIT 

### M ODIFICATIONS



### ...................................................................................... 22 L. R EOPENING FOR 

### C AUSE



### ............................................................................................................. 22 M. P ERMIT 

### E XPIRATION AND 

### R ENEWAL



### ......................................................................................... 23 N. S EVERABILITY 

### C LAUSE



### ............................................................................................................. 23 O. T RANSFER OR 

### A SSIGNMENT OF 

### O WNERSHIP



### ............................................................................. 24 P. E MISSIONS 

### T RADING 

### , M ARKETABLE 

### P ERMITS 

### , E CONOMIC 

### I NCENTIVES



### .................................. 24 Q. N O 

### P ROPERTY 

### R IGHTS 

### C ONVEYED



### ........................................................................................... 24 R. T ESTING 

### R EQUIREMENTS



### .......................................................................................................... 24 S. S OURCE 

### T ESTING 

### P ROTOCOL



### .................................................................................................... 24 T. M ALFUNCTIONS



### ........................................................................................................................ 24 U. C IRCUMVENTION



### ....................................................................................................................... 24 V. M OTOR 

### V EHICLES



### ..................................................................................................................... 24 W. A NNUAL 

### E MISSIONS 

### I NVENTORY



### .............................................................................................. 25 X. O PEN 

### B URNING



### ......................................................................................................................... 25 Y. M ONTANA 

### A IR 

### Q UALITY 

### P ERMITS



### ............................................................................................ 25 Z. N ATIONAL 

### E MISSION 

### S TANDARD FOR 

### A SBESTOS



### ..................................................................... 26 AA. A SBESTOS



### .................................................................................................................................. 26 BB. S TRATOSPHERIC 

### O ZONE 

### P ROTECTION



### – S ERVICING OF 

### M OTOR 

### V EHICLE 

### A IR 

### C ONDITIONERS 

### 26 C C. S TRATOSPHERIC 

### O ZONE 

### P ROTECTION



### – R ECYCLING AND 

### E MISSION 

### R EDUCTIONS



### .................. 26 DD. E MERGENCY 

### E PISODE 

### P LAN



### ...................................................................................................... 27 EE. D EFINITIONS



### .............................................................................................................................. 27


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

APPENDIX B DEFINITIONS AND ABBREVIATIONS ............................................................ B-1OP0691-05 iii Decision: 11/03/10 Effective Date: 12/04/10 

### APPENDIX C NOTIFICATION ADDRESS ES

............................................................................ C-1

APPENDIX D AIR QUALITY INSPECTOR INFORMATION

................................................. D-1

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

APPENDIX F SO 2 

### CEMS ............................................................................................................... F-1

APPENDIX G NO X 

### CEMS .............................................................................................................. G-1

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

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

APPENDIX J MEMS ........................................................................................................................... J -1OP0691-05 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 We t Scrubber
EU06 Fuel (gasoline) Storage Tank None
EU07 Coal Storage Piles None
EU08 Fugitive Coal, Ash, and Lime Handling NoneOP0691-05 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 Co ntaminants 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 Parti culate 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 Particulat e Matter E= 4.10 * P 0.67 or E= 55 * P 0.11

- 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/10 0 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 ou tdoor 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 ou tdoor 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, tr ansportation, 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 park ing 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, M DU 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 * P 0.67 

### For process weight rates in excess of 30 tons per hour: E = 55.0 * P 0.11



### – 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 pou nd 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 ex cess 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 sta tionary 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 documen t 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% Meth od 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.1 5 , B.16 , B.25 , B.27 , B.28 , B.35 , B.36 SO 2 Emissions 1.0 lb sulfur/MMBtu fuel or 2.0 lb SO 2 /MMBtu Continuous

Scrubber Operations an d CEMS Ongoing Semiannual

50 gr sulfur/100 CF fuel Record

Keeping Ongoing Semiannual

B.5 , B.17 , B.28 , .B35 , B.36 NO x

Emissions/A cid 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 Semia nnual

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 SemiannualOP0691-05 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 disc harged 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 sulf ur/MMBtu fuel or 2.0 lb SO 2 

### /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 gas eous fuel (ARM 17.8.322).

B.5. NO X 

### 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,

rec ordkeeping, 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 (A CI) system. MDU shall implement the operation and maintenance of the OAI and ACI syst ems 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, repo rting, 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 Depa rtment 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 wi th 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 approv ed 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 emi ssion limit in III.B.3 (ARM 17.8.322(6)(c)).

B.15. MD U shall monitor compliance with emission limits in III.B.3 pursuant to the requirements in 40 CFR Part 75, and the SO 2 

### 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 m onitor 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 NO X 

### 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 (A ppendix 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).

Recordk ee ping

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

an d 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 opera tions (ARM 17.8.1212).

B.26. MDU shall perform recordkeeping in accordance with the Predictive Opacity Monitoring System Appendi x 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 mai ntaining 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 wel l 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 requ ired 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. EU0 6: Fuel (gasoline) Storage Tank

Condition(s) Pol lutant/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, repo rting, 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. MD U 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. EU0 7: Coal Storage Piles

Condition(s) Pollutant/Parameter Permit Limit Compliance Demonstration Method Frequenc y 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 emi ssions 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. EU0 8: Fugitive Coal, Ash, and Lime Handling

Condition(s) Pollutant/Parameter Permit Limit Compliance Demonstration Method Frequency Reporti ng Requirement
E.1 , E.2 , E.3 , E.4 , E.5 , E.6 , E.7 , E.8 Opacity 4 0% 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 vi sible 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 Met hod 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 hav e 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 MMMM

NNNNN 40 CFR 63, Subparts PPPPP

- TTTTT 40 CFR 63, Subpart WWWWW 40 CFR 63, Subparts YYYYY

ZZZZZ 40 CFR 63, Subpart BBBBBB 40 CFR 63, Subparts DDDDDD

HHHHHH 40 CFR 63, Subparts LLLLLL

TTTTTT 40 CFR 63, Subparts WWWWWW

XXXXXX 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 – Dec ember 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- fe derally 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 reportsOP0691-05 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 immediatecorrective 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, Subchapt er 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 applicableOP0691-05 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 AR M 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 prov ided 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 dete rmining 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 Worksheets2/11/2011



## Appendix C.1 - February 2011 Regional Haze Evaluation for Lewis and Clark Generating Station, Montana Dakota Utilities Table C.1-1 : Control Cost Summary

SO 2 

### Control Cost Summary

Control Technology Controled lb SO 2 /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 $9,685,174 $11,390 $12,776 None Medium Solid Waste Existing Wet Scrubber 0.45 901.9 100.2 $270,000 $101,728 $1,015 NA None Low Waste-water Dry Sorbent Injection and Baghouse 0.45 901.9 100.2 $15,746,000 $2,797,141 $27,912 NA None Medium Solid Waste

Baseline 0.50 1002.1



### NO x 

### 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 $18,786 Ammonia Slip Medium Ammonia in Wastewater Discharge

SNCR + Low NOx Burners with SOFA 0.20 400.9 400.9 $3,686,000 $960,120 $2,395 $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 $1,350,000 $230,704 $767 NA Higher CO Emissions None None
Baseline 0.40 801.7

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 Summary Table Page 1 of 23

## 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 $/ft 3 CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst #3 $/ft 3 Catalyst #4 $/ft 3 Gas Flow Calculations for SCR Catalyst #5 $/ft 3 123,200 dscfm @ 68o F Filter Bags $/bag 17.5% Moisture Tower Packing $/ft 3 850 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 (SO 2 ) 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

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 Utility Chem$ Data 2/11/2011 Page 2 of 23

## 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. 709,089 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 8,976,085 Total Annual Cost (Annualized Capital Cost + Operating Cost) 9,685,174



### 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 11,390 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 SO 2 removed at 1.3:1 stoichiometric ratio Lime:SO2

Appendix C1 Control Cost Worksheets 02112011

## 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 - NA NA - 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 709,089

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) 9,685,174

See Summary page for notes and assumptions

Appendix C1 Control Cost Worksheets 02112011

## 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 $/ft 3 Amount Required 0 ft 3 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 ft 2 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 ft 2 - 4:1 air:cloth ratio assumed to determine baghouse area Cages 10 ft long 5 in dia 13.42 area/cage ft 2 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 Biotreatement 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 Lime 0.00 $/ton 364 lb/hr 1,275 0 $/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 ft 3 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 02112011

## 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. 619,993 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 2,177,147 Total Annual Cost (Annualized Capital Cost + Operating Cost) 2,797,141



### 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 27,912 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 SO 2 removed at 1.3:1 stoichiometric ratio Lime:SO2
6 7 8

Appendix C1 Control Cost Worksheets 02112011

## 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 - NA NA - 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 619,993

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) 2,797,141

See Summary page for notes and assumptions

Appendix C1 Control Cost Worksheets 02112011

## 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 $/ft 3 Amount Required 0 ft 3 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 ft 2 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 ft 2 - 4:1 air:cloth ratio assumed to determine baghouse area Cages 10 ft long 5 in dia 13.42 area/cage ft 2 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 Biotreatement 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 Lime 0.00 $/ton 43 lb/hr 150 0 $/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 ft 3 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

Appendix C1 Control Cost Worksheets 02112011

## 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. 40,901 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 60,827 Total Annual Cost (Annualized Capital Cost + Operating Cost) 101,728



### 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 (SO 2 ) 286.0 1,002.1 70% 0.45 lb/MMBtu 901.9 100.2 1,015 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 SO 2 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 SO 2 removed at 1.1:1 stoichiometric ratio Lime:SO2

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 SO2-Existing Scrubber 2/11/2011 Page 9 of 23

## 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 - NA NA - NA NA - NA NA - NA NA - NA NA - Total Annual Direct Operating Costs 40,901

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) 101,728

See Summary page for notes and assumptions

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 SO2-Existing Scrubber 2/11/2011 Page 10 of 23

## 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 $/ft 3 Amount Required 0 ft 3 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 Biotreatement 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 Lime 0.00 $/ton 36.3 lb/hr 127 0 $/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 ft 3 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

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 SO2-Existing Scrubber 2/11/2011 Page 11 of 23

## 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 $/ft 3 # of Layers 3 Replacement Factor 3 Layers replaced per year = 1 Amount Required 1,121 ft 3 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 ft 2 167 f (h SCR) Q flue gas 252,207 acfm Rx Area 302 193 f (h NH 3 ) 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 ft 3 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 H 2 O per layer Press drop duct 3 in H 2 O 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/ft 3 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

## 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 3,686,000
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 431,574 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 528,546 Total Annual Cost (Annualized Capital Cost + Operating Cost) 960,120



### 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 2,395 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" February, 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\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 NOx LNB&SNCR S&L 2/11/2011 Page 15 of 23

## 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) 3,686,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 3,686,000



### 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 55,290 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 431,574

Indirect Operating Costs Overhead 60% of total labor and material costs 33,174 Administration (2% total capital costs) 2% of total capital costs (TCI) 73,720 Property tax (1% total capital costs) 1% of total capital costs (TCI) 36,860 Insurance (1% total capital costs) 1% of total capital costs (TCI) 36,860 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 347,932 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 528,546
Total Annual Cost (Annualized Capital Cost + Operating Cost) 960,120 See Summary page for notes and assumptions

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 NOx LNB&SNCR S&L 2/11/2011 Page 16 of 23

## 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 $/ft 3 Amount Required 12 ft 3 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 $/ft 3 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/ft 3 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 55,290 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 ft 3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization CO Catalyst 650 $/ft3 0 ft 3 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\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 NOx LNB&SNCR S&L 2/11/2011 Page 17 of 23

## 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" February, 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\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 NOx SNCR S&L 2/11/2011 Page 18 of 23

## 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\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 NOx SNCR S&L 2/11/2011 Page 19 of 23

## 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 $/ft 3 Amount Required 12 ft 3 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 $/ft 3 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/ft 3 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 ft 3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization CO Catalyst 650 $/ft3 0 ft 3 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\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 NOx SNCR S&L 2/11/2011 Page 20 of 23

## 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 1,350,000
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 30,796 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 199,908 Total Annual Cost (Annualized Capital Cost + Operating Cost) 230,704



### 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 501.1 300.6 767 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" February, 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\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 NOx LNB S&L 2/11/2011 Page 21 of 23

## 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 1,350,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,350,000



### 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 20,250 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 30,796

Indirect Operating Costs Overhead 60% of total labor and material costs 18,478 Administration (2% total capital costs) 2% of total capital costs (TCI) 27,000 Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,500 Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,500 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 127,430 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 199,908
Total Annual Cost (Annualized Capital Cost + Operating Cost) 230,704 See Summary page for notes and assumptions

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 NOx LNB S&L 2/11/2011 Page 22 of 23

## 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 $/ft 3 Amount Required 12 ft 3 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 $/ft 3 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/ft 3 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 20,250 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 ft 3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization 2 CO Catalyst 650 $/ft3 0 ft 3 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\WorkFiles\Control Cost Worksheets\Appendix C1 Control Cost Worksheets 02112011 NOx LNB S&L 2/11/2011 Page 23 of 23

# Appendix C. 2

Low Load Operation NOx Control Cost Worksheets2/11/2011



## 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

NO x 

### 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 $31,985 Ammonia Slip Medium Ammonia in Wastewater Discharge

SNCR + Low NOx Burners with SOFA 0.23 220.9 134.5 $3,686,000 $764,139 $5,683 $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 $1,350,000 $230,704 $2,184 NA Higher CO Emissions None None
Baseline 0.37 355.3

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets Summary Table Page 1 of 14

## 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 $/ft 3 CO Catalyst 650 $/ft 3 Vendor quote if needed Catalyst #3 $/ft 3 Catalyst #4 $/ft 3 Gas Flow Calculations for SCR Catalyst #5 $/ft 3 59,033 dscfm @ 68o F Filter Bags $/bag 17.5% Moisture Tower Packing $/ft 3 850 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 (SO 2 ) 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

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets Utility Chem$ Data 2/11/2011 Page 2 of 14

## 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 $/ft 3 # of Layers 3 Replacement Factor 3 Layers replaced per year = 1 Amount Required 537 ft 3 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 ft 2 167 f (h SCR) Q flue gas 120,849 acfm Rx Area 145 454 f (h NH 3 ) 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 ft 3 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 H 2 O per layer Press drop duct 3 in H 2 O 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/ft 3 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

## 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 3,686,000
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 235,593 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 528,546 Total Annual Cost (Annualized Capital Cost + Operating Cost) 764,139



### 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 5,683 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" February, 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\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets NOx LNB&SNCR S&L 2/11/2011 Page 6 of 14

## 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) 3,686,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 3,686,000



### 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 55,290 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 235,593

Indirect Operating Costs Overhead 60% of total labor and material costs 33,174 Administration (2% total capital costs) 2% of total capital costs (TCI) 73,720 Property tax (1% total capital costs) 1% of total capital costs (TCI) 36,860 Insurance (1% total capital costs) 1% of total capital costs (TCI) 36,860 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 347,932 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 528,546
Total Annual Cost (Annualized Capital Cost + Operating Cost) 764,139 See Summary page for notes and assumptions

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets NOx LNB&SNCR S&L 2/11/2011 Page 7 of 14

## 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 $/ft 3 Amount Required 12 ft 3 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 $/ft 3 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/ft 3 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 55,290 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 ft 3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization CO Catalyst 650 $/ft3 0 ft 3 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\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets NOx LNB&SNCR S&L 2/11/2011 Page 8 of 14

## 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" February, 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\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets NOx SNCR S&L 2/11/2011 Page 9 of 14

## 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\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets NOx SNCR S&L 2/11/2011 Page 10 of 14

## 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 $/ft 3 Amount Required 12 ft 3 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 $/ft 3 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/ft 3 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 ft 3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization CO Catalyst 650 $/ft3 0 ft 3 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\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets NOx SNCR S&L 2/11/2011 Page 11 of 14

## 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 1,350,000
Operating Costs Total Annual Direct Operating Costs Labor, supervision, materials, replacement parts, utilities, etc. 30,796 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 199,908 Total Annual Cost (Annualized Capital Cost + Operating Cost) 230,704



### 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 2,184 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" February, 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\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets NOx LNB S&L 2/11/2011 Page 12 of 14

## 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 1,350,000

Adjusted TCI for Replacement Parts (Catalyst, Filter Bags, etc) for Capital Recovery Cost 1,350,000



### 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 20,250 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 30,796

Indirect Operating Costs Overhead 60% of total labor and material costs 18,478 Administration (2% total capital costs) 2% of total capital costs (TCI) 27,000 Property tax (1% total capital costs) 1% of total capital costs (TCI) 13,500 Insurance (1% total capital costs) 1% of total capital costs (TCI) 13,500 Capital Recovery 0.0944 for a 20- year equipment life and a 7% interest rate 127,430 Total Annual Indirect Operating Costs Sum indirect oper costs + capital recovery cost 199,908
Total Annual Cost (Annualized Capital Cost + Operating Cost) 230,704 See Summary page for notes and assumptions

P:\Mpls\26 MT\41\26411001 MDU L&C Regional Haze Eval\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets NOx LNB S&L 2/11/2011 Page 13 of 14

## 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 $/ft 3 Amount Required 12 ft 3 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 $/ft 3 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/ft 3 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 20,250 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 ft 3 0 0 $/ft3, 0 ft3, 8760 hr/yr, 80% utilization 2 CO Catalyst 650 $/ft3 0 ft 3 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\WorkFiles\Control Cost Worksheets\Appendix C2 23MW NOx Control Cost Worksheets NOx LNB S&L 2/11/2011 Page 14 of 14

# 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. A s 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 2010 1



### . 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 2010Average Energy Content (btu)



### Year



# Figure D1. Coal Energy Content Data

Weekly Monthly
Annual0.20

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 2010Average Sulfur Content (%)



### Year



# Figure D2. Coal Sulfur Content Data

Weekly Monthly Annual5

10 15 20 25 30

Apr 2006 Oct 2006 May 2007 Dec 2007 Jun 2008 Jan 2009 Jul 2009 Feb 2010 Aug 2010AverageCalcium Content (%)



### Year



# Figure D3. Coal Calcium Content Data

Weekly Monthly
Annual6

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 2010Average Ash Content (%)



### Year



# Figure D4. Coal Ash Content Data

Weekly Monthly Annual28

30 32 34 36 38 40

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



### NH 3 

### Slip ( ppm ) = NH 3 

### Rate � lb hr � × 1 hr 60 min × 1 lb

− mol 17

. 03 lb × 385 scf lb

− mol × min 160 , 934 scf × 10 6 

### parts million

Where: NH 3 

### Slip = Design basis ammonia slip range (ppm) NH 3 

### Ra te = 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



### NH 3 

### � mg L � = � NH 3 

### 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 M ontana DEQ Water Quality Circular i

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.