MONTANA-DAKOTA

UTILITIES CO.

ADMs;on of MDU RSSOUTC6S Group, Inc.

400 North Fourth Street

Bismarck, ND 58501

(701) 222·7900

March 17, 2009

U.S. Environmental Protection Agency

1595 Wynkoop Street

Denver, Colorado 80202-1129

Attention: Laurel Dygowski, 8P-AR

Re: Montana Dakota Utilities Co. Response to Reasonable Progress Request for Inforn1ation

Pursuant to Section 114(a) of the Clean Air Act - Lewis & Clark Station, 35023 Highway

23, South, Sidney, Richland County, Montana

Dear Ms. Dygowski:

Attached are Montana Dakota Utilities Co.'s (Montana-Dakota's) responses to the abovereferenced Request for Inforn1ation, dated January 29, 2009, received on February 2, 2009. The

Request seeks information necessary to allow EPA to establish Reasonable Progress Goals

(RPGs) as provided in Section 51.308(d)(1 ) of the Regional Haze Rules promulgated by EPA on

July 1, 1999 or, alternatively, to allow the State of Montana to establish the goals should it

choose to resume development of its Regional Haze SIP at a future date. The Regional Haze

Rules specify that RPGs are interim goals that represent incremental visibility improvement over

time toward achieving the goal of natural background conditions by 2064. The goals are to be

developed in consultation with other affected states and Federal Land Managers and are intended

to improve visibility on the haziest days and to ensure no degradation in visibility on the clearest

days over the period of each implementation plan for each Class I area in Montana.

To determine what constitutes reasonable progress EPA will consider the following four factors:

(1) the cost of compliance; (2) the time necessary for compliance; (3) the energy and non-air

quality environmental impacts of compliance; and (4) the remaining useful life of existing

sources that contribute to visibility impairment. CAA § 169A(g)(1); 40 C.F.R. §

51.308(d)(1)(i)(A). You indicated during our March 5,2009, telephone conference call that EPA

will supply the enclosed responses to a consulting firn1 retained by the agency to assist in

developing the RPGs for Montana. By mid- to late Summer 2009 stakeholdcrs like MontanaDakota will be supplied a demonstration as to how the above factors either have been or will be

considered in setting the RPGs for each Class I area in the State.

We believe that the demonstration EPA will supply should also, among other things: (a)

establish applicable baseline and natural visibility conditions (and the basis for the same); (b)

establish a Uniform Rate of Progress (URP) (and the basis for the same); (c) identify the

measures aimed at achieving the URP; and (d) identify the degree of visibility improvement in

the forn1 of emissions reductions that can be expected from existing or forecast local, State and

Federal programs (including BART), which, alone, may suffice for demonstrating progress for

Laurel Dygowski

March 17, 2009

Page 2

RPG planning periods. In Montana, EPA's demonstration may be complicated by transboundary sources located in Canada that contribute to visibility issues. Therefore, in addition to

the factors referenced at 40 C.F.R. 51.308(d)(1)(i)(A), and immediately above, it will be

important for EPA's demonstration to consider trans-boundary sources over which it has no

authority to control or regulate.

We have made every effort to provide complete and accurate responses to the Request for

Information given the constraints posed by the time provided to respond. Bye-mail to you dated

March 6, 2009, I posed a number of questions regarding certain elements of the Request. I also

asked for an extension of time to March 31, 2009, to supply the response. Since I received no

reply from you to the questions I posed or to the request for an extension of time to respond,

Montana-Dakota has made its best effort to respond accurately and completely. We reserve the

right to supplement the responses in the future, as necessary, to further address any items we or

you may subsequently determine require further explanation, supplementation, amendment or

reVISIOn.

Should you have any questions regarding the attached responses, or this cover letter, please do

not hesitate to call me.

Thank you.

Sincerely yours,

~~«::J.. Abbie Krebsbach

Environmental Manager

Enclosure

Statement of Certification

I certify under penalty oflaw that I have personally examined and am familiar with the

information submitted in Attachment "A" to this letter and all related attachments and that,

based on my inquiry of those individuals immediately responsible for obtaining such

information, I believe that the information is true, accurate, and complete. I am aware that there

~~~~~~:~~~;/ penalties for submilling i~ibilitY offine of

Andrea Stom erg

Vice President, Electric Supply

\1 \N\.cu c..~ ,2009

Attachment A

Montana Dakota Utilities Co. - Lewis and Clark Station

Request for Information Pursuant to Section 114 of the CAA

March 17, 2009

Part I: General Facility Data

1. Name of facility: Lewis and Clark Station

2: Complete street address offacility (physical location):

a. Street Address: 35023 Hwy 23 South

Southwest 1/4, Section 9, Township 22 North, Range 59 East

b. City: Sidney

c. State: Montana

d. Zip: 59270

e. County: Richland County

3: Facility contact

a. Name (First Name, Last Name): Abbie Krebsbach

b. Title: Environmental Manager

c. Telephone number: (701) 222-7844

d. Fax number: (701) 222-7845

e. E-mail: abbie.krebsbach@mdu.com

Part II: Boiler Emission Unit Data (Please complete entire section for each boiler,

additional copies may be necessary)

1: Emission Unit Name: EU1 (Tangential Coal/Natural Gas boiler)

a. Type ofBoi1er (e.g., spreader stoker, suspension-fired, fluidized bed): Dry

Bottom, Tangential-Fired Coal/Natural Gas Boiler

b. Make: Combustion Engineering

c. Model: Not specified in the original design plans and specifications

d. Model Year: This was not a package boiler. The model year was not

specified in the origimi.l design plans and specifications. Construction of

the boiler began in 1957 and was completed in 1958.

e. Year Installed: Construction began in 1957. The plant commenced

operation in 1958.

f. Expected equipment life: Not specified in the original design plans and

specifications. There are currently no plans or schedule for removing the

facility from service.

g. Unit Is Currently Operational (Check one): DNO

If you answered YES above, continue on to h: If you answered NO above,

answer the following and then continue to next unit:

i. Date of final operation:

ii. Will this unit be operational in the future (Check One)?

DYES DNa

h. Unit Capacity (MW gross/net): 52 MW gross/48 MW net. These values

reflect the maximum sustainable capacity ofthe unit when firing on both

coal and natural gas. The data provided in this request can be assumed to

be representative ofthe unit firing on coal alone, since the time periods

when natural gas is used are very short. [Source: operational history]

2: Boiler Unit Outlet Information (Complete the following exhaust gas parameters for

the indicated boiler. Ifthe boiler shares a common stack with another boiler, please

only provide exhaust information for the specified boiler).

a. Does this unit share an exhaust stack with another unit? (Check One)

DYES

b. Maximum Boiler Exhaust Volumetric Flowrate (acfm): 260,000 ACFM

[Source: 1996 Title V App, Section 5]

c. Maximum Boiler Exhaust Temperature (F): 1550F [Source: 1996 Title V

App, Section 5]

d. Boiler Exhaust Moisture (%): 22% [Source: 2008 GE PM Test]

e. Stack Height (ft): 250 ft [Source: 1996 Title V App, Section 5]

f. Stack Diameter (ft): 8.75 ft at the outlet [Source: Drawing # L-22505

Sheet #S 14-1 0]

g. Maximum Gross Heat Input (MMBtu/hr): 600 MMBtu/hr [Source: 1996

Title V App, Section 5]

h. Annual Hours of Operation:

Actual Annual Hours of Operation

Year Hours of Operation

2005 6722 (scheduled outage)

2006 8139

2007 7669

2008 8156

[Source: Form 20]

J. Design Percent Load (Capacity Factor): The design percent load or

capacity factor are not specified in the original design plans and

specifications. The ability to operate continuously at 52 MW gross/48 MW

net is limited primarily by the quality ofthe coal. The actual annual net

capacity factor is calculated by dividing the annual net generation in

MWhrs by the product of 8760 hours and the maximum sustainable net

capacity of 48 MW. [Source: Form 20]

Actual Annual Net Capacity Factor

Year Net Capacity Factor

2005 68% (scheduled outage)

2006 80%

2007 75%

2008 79%

J. 2001 - 2003 Maximum 24-hour Average Uncontrolled PM Emissions

(lb/hr): There were no uncontrolled PM emissions for the time period

specified. It is not possible to operate the boiler unless the control system is

in operation. Ifthe control system shuts down, the boiler is automatically

shut down.

2

k. 2001 - 2003 Maximum 24-hour Average Uncontrolled NOx Emissions

(lb/hr): There were no uncontrolled NOx emissions for the time period

specified. It is not possible to operate the boiler unless the control system is

in operation. The system is adjusted manually for optimum NOx emissions

control. Ifthe control system malfunctions, but does not shut down, the

boiler is shut down manually.

1. 2001 - 2003 Maximum 24-hour Average Uncontrolled S02 Emissions

(lb/hr): There were no uncontrolled S02 emissions for the time period

specified. It is not possible to operate the boiler unless the control system is

in operation. If the control system shuts down, the boiler is automatically

shut down.

3: Existing Pollution Control Equipment (Complete the following for each piece of

control equipment, make additional copies to provide information for all equipment).

a. PM Control Technology Information:

Multi-Cyclone Dust Collector

i. Type of PM Control Technology: Multi-Cyclone Dust Collector

[Source: 1996 Title V App, Section 6]

ii. Make/Model of PM Control Technology: Western Precipitation

Corporation! 9VGR-12 [Source: 1996 Title V App, Section 6]

iii. Year Installed: 1957 [Source: 1996 Title V App, Section 6]

iv. Installed Cost ofControl Device ($/yr): Not itemized in original unit

cost. Control equipment cost included in the cost ofthe boiler.

v. Direct Annual Cost ofControl Device ($/yr): (2008 Costs)

-O&M: $79,547.80 (Approximate cost of$70,912.80 for ash

hopper operations and $8,635.00 for multi-cyclone dust

collector and ash hopper maintenance. [Source: accounting]

vi. Expected life of equipment: Not specified in the original design

plans and specifications. There are currently no plans or schedule for

removing the existing control equipment from service.

vii. Relevant sizing information (Please provide information sufficient

to apply the EPA Air Pollution Control Cost Manual- Sixth Edition

(EPA 452/B-02-001) Section 6 -- Particulate Matter Controls Chapter 2

- Wet Scrubbers for Particulate Matter): EPA 452/B-02-001 does not

yet have a section that is applicable to multi-cyclone dust collectors.

Section 6 chapter 4, Inertial Impactors, is not available in the manual.

Vane Type: VGR

Tube Diameter: 9"

Total Tubes: 406

[Source: Manufacturer's Installation and Operating Manual for

Multiclone - Western Precipitation Corporation]

viii. Design control efficiency (%): 75%-80% of PM [Source:

1996 Title V App, Section 6]

ix. 2007 Average Controlled PM Emissions (lb/hr) and method of

determination: The multi-cyclone dust collector is not the final PM

control device. The wet scrubber, which is in continuous operation

3

when the boiler is firing, is located after the multi-cyclone dust

collector. See Section ix. ofthe Flooded Disc Wet Scrubber.

Flooded Disc Wet Scrubber

i. Type of PM Control Technology: Flooded Disc Wet Scrubber

[Source: 1996 Title V App, Section 6]

ii. Make/Model ofPM Control Technology: Research - Cottrell/ model

not specified [Source: 1996 Title V App, Section 6]

iii. Year Installed: 1975 [Source: 1996 Title V App, Section 6]

iv. Installed Cost ofControl Device ($/yr): $14,779,668 in 2008

dollars. The installed cost ofthe control device from 1975 and 1976

dollars was escalated to 2008 dollars using the Chemical Engineering

Plant Cost Index. [Source: accounting]

v. Direct Annual Cost ofControl Device ($/yr): (2008 Costs)

-O&M: $24,911.27 (Approximate cost of outage cleaning and

I&C maintenance.) [Source: accounting]

-Waste Disposal: $180,000 (Approximate annual cost of

scrubber pond maintenance and ash disposal.) [Source:

accounting]

-Power: $123,134.18 (Total scrubber power consumption plus

half the ID fan power consumption for 2008 at $27.14 /MW.)

[Source: accounting]

vi. Expected life of equipment: Not specified in the original design

plans and specifications. There are currently no plans or schedule for

removing the existing control equipment from service.

vii. Relevant sizing information (Please provide information sufficient

to apply the EPA Air Pollution Control Cost Manual -.- Sixth Edition

(EPA 452/B-02-001) Section 6 - Particulate Matter Controls Chapter 2

- Wet Scrubbers for Particulate Matter):

-Particle Size Distribution:

Aerodynamic

Diameter at Unit % less

Density (Microns) than

0.6 4

1 5.6

2 17

3 28

4 37

7 52

10 57

14 62

[Source: Scrubber Operatmg Manual, Section 4]

Loading: 1.12 gr/dscf- 1.43 gr/dscf[Source: Scrubber

Operating Manual, Section 4]

-Waste gas flow

Rate: 168,930 acfm - 313,730 acfm [Source: Scrubber

Operating Manual, Section 4]

Temperature: 3500 F - 4200 F [Source: Scrubber

Operating Manual, Section 4]

4

Humidity: 14.5% - 17.8% [Source: Scrubber Operating

Manual, Section 4]

-Gas velocity and pressure drop

Gas velocity: There is no value specified in the Scrubber

Operating Manual. However, this value has been

estimated to be approximately 126 feet per second based

on the normal disk operating height of 14 inches and

normal operating conditions. [Source: Scrubber

Operating Manual, Section 4]

Pressure Drop: 12 inches water column (IWC). The

Scrubber Operating Manual specifies 13 IWC, but

operational experience demonstrates 12 IWC is optimal.

-Liquid-to-gas ratio: There is no value specified in the Scrubber

Operating Manual. However, this ratio has been estimated to be

approximately 12 gallons per 1,000 actual cubic feet based on

normal operating conditions. [Source: Scrubber Operating

Manual, Section 4]

-Droplet size: There is no value specified in the Scrubber

Operating Manual and the value is currently unknown.

-Residence time: There is no value specified in the Scrubber

Operating Manual. However, this value has been estimated to

be approximately 7.0 seconds based on norn1al operating

conditions. [Source: Scrubber Operating Manual, Section 4]

viii. Design control efficiency (%): 98% of PM [Source: 1996 Title V

App, Section 6, and Scrubber Operating Manual, Section 3]

ix. 2007 Average Controlled PM Emissions (lb/hr) and method of

determination: 47.1 lb/hr [Source: Calculated from GE 2007 Particulate

Matter Emissions Compliance Test Report]

b: NOx Control Technology Information:

i. Type ofNOx Control Technology: Low NOx Firing System

[ABB NOx Tuning Report]

ii. Make/Model of NOx Control Technology: ABB C-E Services,

Inc.lLevel 1 Low NOx Firing System with Close-Coupled Overfire Air

[ABB NOx Tuning Report]

iii. Year Installed: 1996 [ABB NOx Tuning Report]

iv. Installed Cost ofControl Device ($/yr): $463,978 in 2008 dollars.

The installed cost ofthe control device from 1996 dollars was escalated

to 2008 dollars using the Chemical Engineering Plant Cost Index.

[Source: accounting]

v. Direct Annual Cost ofControl Device ($/yr):

-O&M: $52,861.10 (Approximate cost of $50,000 per year for

burner tip replacement and $2861.10 per year for burner

cleaning and checks.) [Source: accounting]

vi. Expected life of equipment: Not specified in the original design

plans and specifications. There are currently no plans or schedule for

removing the existing control equipment from service.

5

vii. Relevant sizing information (Please provide information sufficient

to apply the EPA Air Pollution Control Cost Manual- Sixth Edition

(EPA 452/B-02-001) Section 4 - NOx Controls Section 4.2 - NOx

Post-Control Chapter 1 - Selective Non-Catalytic Reduction and the

EPA Air Pollution Control Cost Manual - Sixth Edition (EPA 452/B02-001) Section 4 - NOx Controls Section 4.2 - NOx Post-Control

Chapter 2 -- Selective Catalytic Reduction): EUI does not use a

catalytic form ofNOx reduction. EPA 452/B-02-001 does not yet have

a section that is applicable to close-coupled overfire air NOx

combustion control.

viii. Design control efficiency (%): A design control efficiency was not

specified in the design manual ofthe overfire air control system,

However, a current control efficiency have been estimated to be 33%.

(Based on the average NOx emission rates calculated using AP-42

emission rate of 0.60 lb/mmbtu before installation ofthe control system

compared with the manufacturer's guaranteed NOx rate of 0.40 lb

NOx/MMBtu provided in the ABB Tuning Report. The efficiency has

been confirmed with measured values. Note: 0.40 lb NOx/MMBtu is

also the maximum allowable NOx emission rate in the MT DEQ air

permit.

ix. 2007 Average Controlled NOx Emissions (lb/hr): 229.27 lbs/hr

[Source: Calculations based on 2007 annual emissions inventory data]

c. S02 Control Technology Information:

i. Type ofS02Control Technology: Flooded Disc Wet Scrubber

[Source: 1996 Title V App, Section 6]

ii. Make/Model of S02 Control Technology: Research - Cottrell/not

specified [Source: 1996 Title V App, Section 6]

iii. Year Installed: 1975 [Source: 1996 Title V App, Section 6]

iv. Installed Cost ofControl Device ($/yr): $14,779,668 in 2008

dollars. The installed cost ofthe control device from 1975 and 1976

dollars was escalated to 2008 dollars using the Chemical Engineering

Plant Cost Index. [Source: accounting]

v. Direct Annual Cost of Control Device ($/yr): (2008 Costs)

-O&M: $24,911.27 (Approximate cost of outage cleaning and

I&C maintenance.) [Source: accounting]

-Chemicals: $36,452.90 (Cost of 142.68 tons oflime including

delivery.) [Source: accounting]

-Waste Disposal: $180,000 (Approximate annual cost of

scrubber pond maintenance and ash disposal.) [Source:

accounting]

-Power: $123,134.18 (Total scrubber power consumption plus

halfthe ID fan power consumption for 2008 at $27. 14/MW)

[Source: historical operation and accounting]

vi. Expected life of equipment: Not specified in the original design

plans and specifications. There are currently no plans or schedule for

removing the existing control equipment from service.

6

vii. Relevant sizing information (Please provide information sufficient

to apply the EPA Air Pollution Control Cost Manual- Sixth Edition

(EPA 452/B-02-00 1) Section 5 - SOz and Acid Gas Controls Section

5.2 - Post-Controls Chapter 1 - Wet Scrubbers for Acid Gas):

-Waste gas flow rate (acfm):

168,930 acfm - 313,730 acfm [Source: Scrubber

Operating Manual, Section 4]

-Waste gas composition and concentration ofthe pollutants

in the gas stream:

378 PPM -1691 PPM SOz [Source: Scrubber Operating

Manual, Section 4]

-Solvent flow rate (gpm):

2200 - 3700 gpm [Source: Scrubber Operating Manual,

Section 4]

-Properties ofthe pollutant, waste gas and solvent:

diffusivity, viscosity, density and molecular weight

The properties ofthe pollutant, waste gas and solvent are currently

unknown.

viii. Design control efficiency (%): The original design control

efficiency is 15% or greater; the actual control efficiency has been

demonstrated to be approximately 60%. [Source: Scrubber Operating

Manual, Section 3, and actual emissions measurement]

ix. 2007 Average Controlled SOz Emissions (lb/hr): 306.39 lbs/hr

[Source: Calculations based on the 2007 annual emissions inventory

data]

The following information should be completed using data for the year 2002. If

informationfor 2002 is not representative ofcurrent operations (for example, ifthis

unit is no longer using natural gas), provide information for a representative year and

provide reasonsfor why the alternative year is more representative than 2002.

4: Fuel Information: Information provided is for year 2002.

Heating Sulfur Ash I

Amount of Value of Max Fuel Content Content,

Fuel Type Fuel Fuel Firing Rate of Fuel of Fuel

Liqnite 283,202 Tons 6658 Btu/lb 46.8 Tons/hr 0.51% 9.30%

Pipeline Natural 667.75 0.02

Gas 14133DKT 1200 Btu/cf DKT/hr grief 0%

7